ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - Feb. 18, 2016) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS), a leader in the North American electric and gas utility industry, released its 2015 annual results today. Driven by its U.S. utility acquisitions, gains on non-core asset dispositions, completion of the Waneta hydroelectric generating facility ("Waneta Expansion"), and strong results from its Canadian utilities, Fortis' net earnings attributable to common equity shareholders for 2015 were $728 million, or $2.61 per common share, compared to $317 million, or $1.41 per common share, for 2014. For the fourth quarter of 2015, net earnings attributable to common equity shareholders were $135 million, or $0.48 per common share, compared to $113 million, or $0.44 per common share, for the same period in 2014.
"Fortis had a year of transformation and growth in 2015, with all utilities contributing," said Barry Perry, President and Chief Executive Officer, Fortis. "We delivered a record year in earnings, which demonstrates the success of our growth strategy. We also advanced our business on several fronts. We successfully integrated our Arizona utility; divested non-core assets to focus on the core utility business; and sharpened our focus on additional investments within our franchise areas.
"Last week we announced the acquisition of ITC, a premier pure-play transmission utility in a transaction valued at US$11.3 billion," continued Mr. Perry. "We are very excited about this opportunity to continue our growth strategy, further strengthen and diversify our business, and also accelerate our growth. We continue to be committed to profitable growth that adds value for our shareholders."
Strong earnings and cash flow; successful execution of capital program
- On an adjusted basis, net earnings attributable to common equity shareholders for 2015 were $589 million, or $2.11 per common share, an increase of $195 million, or $0.36 per common share, over 2014. On an adjusted basis, for the fourth quarter of 2015, net earnings attributable to common equity shareholders were $142 million, or $0.51 per common share, an increase of $27 million, or $0.06 per common share, over the same period in 2014. A reconciliation of adjusted net earnings and adjusted earnings per common share is provided in the Corporation's 2015 Management Discussion and Analysis.
- Factors that resulted in growth in adjusted earnings per common share included:
- a full year's contribution from UNS Energy in Arizona, which was acquired in mid-August 2014, partially offset by Corporate finance charges and an increase in the weighted average number of common shares outstanding associated with the acquisition.
- contribution of $22 million for the year and $6 million for the fourth quarter from the Waneta Expansion, which came online in early April 2015;
- rate base growth associated with capital expenditures and growth in the number of customers at FortisAlberta;
- a higher allowance for funds used during construction at FortisBC Energy. The timing of earnings associated with regulatory deferral mechanisms at FortisBC Energy and FortisBC Electric also had an overall favourable impact on the fourth quarter of 2015.
- the resetting of customer rates at Central Hudson, effective July 1, 2015;
- the continued strength of the US dollar relative to the Canadian dollar. On an annual basis, earnings per common share are affected by approximately $0.04 for each $0.05 change in the US dollar-to-Canadian dollar exchange rate.
- Earnings growth was tempered by an increase in Corporate expenses and lower earnings contribution due to the sale of the commercial real estate and hotel assets.
- Cash flow from operating activities for 2015 totalled $1.7 billion, 70% higher than last year. The increase was driven by higher cash earnings and favourable changes in working capital.
- Consolidated capital expenditures for 2015 totalled $2.2 billion, the Corporation's largest annual capital program to date, and was in line with the Corporation's forecast. The $900 million Waneta Expansion was completed in 2015, ahead of schedule and within budget, and progress continues on the $440 million Tilbury liquefied natural gas facility expansion in British Columbia.
Continuation of growth strategy through acquisitions
Fortis has grown its business through strategic acquisitions that have also contributed to strong organic growth over the past decade. On February 9, 2016, Fortis and ITC Holdings Corp. ("ITC") (NYSE:ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. ITC is the largest independent pure-play electric transmission company in the United States. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 Fortis common shares per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness. The financing of the Acquisition has been structured to allow Fortis to maintain investment-grade credit ratings and is consistent with the Corporation's existing capital structure. Financing of the cash portion of the Acquisition will be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of up to 19.9% of ITC to one or more infrastructure-focused minority investors.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, the United States Federal Energy Regulatory Commission. The closing of the Acquisition is expected to occur in late 2016.
Additionally, in December 2015 Fortis announced the acquisition of the Aitken Creek Gas Storage Facility ("Aitken Creek") for approximately US$266 million. Aitken Creek is the largest gas storage facility in British Columbia with a total working gas capacity of 77 billion cubic feet and is an integral part of Western Canada's natural gas transmission network. The acquisition is subject to regulatory approval and is expected to close in the first half of 2016.
Regulatory proceedings
Fortis continues to focus on maintaining constructive regulatory relationships and outcomes across its utilities and its regulatory calendar remains very active.
In November 2015 Tucson Electric Power Company ("TEP"), UNS Energy's largest utility, filed a general rate application with the Arizona Corporation Commission requesting new retail rates to be effective January 1, 2017, using the year ended June 30, 2015 as a historical test year. 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 increased from 43.5% to approximately 50%.
Newfoundland Power recently filed a general rate application for 2016 and FortisBC Energy, the benchmark utility in British Columbia, filed its application to review cost of capital for 2016. The regulator in Alberta has also initiated a generic cost of capital proceeding for 2016 and 2017, which includes FortisAlberta.
Outlook
Fortis is focused on closing the acquisition of ITC by the end of 2016. The Acquisition is in alignment with the Corporation's business model and acquisition strategy, and is expected to provide approximately 5% accretion to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses and assuming a stable currency exchange environment. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.
Substantially all of Fortis' assets are low-risk, regulated utilities and long-term contracted energy infrastructure. No single regulatory jurisdiction comprises more than one-third of total assets. Over the five-year period through 2020, excluding the acquisition of ITC, the Corporation's highly executable capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to almost $21 billion in 2020 and produce a five-year compound annual growth rate in rate base of approximately 5%.
On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the acquisition of ITC. Following the Acquisition, Fortis will be one of the top 15 North American public utilities ranked by enterprise value, with an estimated enterprise value of $42 billion. Additionally, ITC's midyear rate base, including construction work in progress, is expected to increase at a compound annual growth rate of approximately 7.5% through 2018, based on ITC's planned capital expenditure program.
Fortis continues to target 6% average annual dividend growth through 2020. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of assets and record of operational excellence. The pending acquisition of ITC further supports this dividend guidance.
Fortis expects long-term sustainable growth in rate base, assets and earnings resulting from strategic acquisitions and investment in its existing utility operations. The Corporation is also committed to identifying and executing on opportunities for incremental rate base and earnings growth through additional investments in existing service territories, and in new franchise areas.
Teleconference to Discuss 2015 Annual Results
A teleconference and webcast will be held on February 18 at 9:00 a.m. (Eastern). Barry Perry, President and Chief Executive Officer, Fortis, and Karl Smith, Executive Vice President, Chief Financial Officer, Fortis, will discuss the Corporation's 2015 annual results.
Analysts, members of the media and other interested parties in North America are invited to participate by calling 1.877.223.4471. International participants may participate by calling 647.788.4922. Please dial in 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Corporation's website, www.fortisinc.com.
A replay of the conference will be available two hours after the conclusion of the call until March 18, 2016. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 22316534.
| Management Discussion and Analysis |
| For the year ended December 31, 2015 |
| Dated February 17, 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 Audited Consolidated Financial Statements and notes thereto for the year ended December 31, 2015. Financial information for 2015 and comparative periods contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs based on information currently available.
The forward-looking information in the MD&A includes, but is not limited to, statements related to the acquisition of ITC Holdings Corp. ("ITC"), the expected timing and conditions precedent to the closing of the acquisition of ITC, including shareholder approvals of both ITC and Fortis, regulatory approvals, governmental approvals and other customary closing conditions; the expectation that Fortis will borrow funds to satisfy its obligation to pay the cash portion of the purchase price and will issue securities to pay the balance of the purchase price; the assumption of ITC debt and expected maintenance of investment-grade credit ratings; the impact of the acquisition on the Corporation's earnings, midyear rate base, credit rating, estimated enterprise value and compound annual growth rate; the expectation that the acquisition of ITC will be accretive in the first full year following closing and that the acquisition will support the average annual dividend growth target of Fortis; the expectation that the Corporation will become a U.S. Securities and Exchange Commission registrant and have its common shares listed on the New York Stock Exchange in connection with the acquisition; the expectation that Fortis will identify one or more minority investors to invest in ITC; the annualized 2016 common share dividend; targeted annual dividend growth through 2020; the expectation that there will be a significant reduction in the use of coal in certain of UNS Energy's generating facilities by 2022; the acquisition of a share of Aitken Creek Gas Storage facility, the expected timing, total expected consideration and conditions precedent to the closing of such acquisition, including regulatory approval; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the expectation that midyear rate base will increase from 2016 to 2020;
the Corporation's forecast gross consolidated capital expenditures for 2016 and total capital spending over the five-year period from 2016 through 2020; the nature, timing and expected costs of certain capital projects including, without limitation, the Tilbury liquefied natural gas ("LNG") facility expansion, the pipeline expansion to the Woodfibre LNG site, the development of a diesel power plant in Grand Cayman, the Residential Solar Program, the Gas Main Replacement Program, the Lower Mainland System Upgrade, the Pole Management Program, 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 cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt offerings; the expectation that the Corporation's subsidiaries will be able to source the cash required to fund their 2016 capital expenditure programs, operating and interest costs, and dividend payments; the expected consolidated fixed-term debt maturities and repayments in 2016 and on average annually over the next five years; the expectation that long-term debt will not be settled prior to maturity; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to capital in the near to long terms;
the expectation that the combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2016; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation that economic conditions in Arizona will improve; 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 Corporations consolidated financial statements.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities including natural gas related infrastructure and generation; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy;
the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans and environmental laws 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; new or revised environmental laws and regulations will not severely affect the results of operations; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2018 or the adoption of International Financial Reporting Standards after 2018 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2016 include, but are not limited to: uncertainty regarding the completion of the acquisition of ITC including but not limited to the receipt of shareholder approvals of ITC and Fortis, the receipt of regulatory and other governmental approvals, the availability of financing sources at the desired time or at all, on cost-efficient or commercially reasonable terms and the satisfaction or waiver of certain other conditions to closing; uncertainty related to the realization of some or all of the expected benefits of the acquisition of ITC; uncertainty regarding the outcome of regulatory proceedings of the Corporation's utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders' equity at the Corporation's regulated utilities; the impact of fluctuations in foreign exchange rates; and risk associated with the impact of less favorable economic conditions on the Corporation's results of operations.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is a leader in the North American electric and gas utility business, with total assets of approximately $29 billion and fiscal 2015 revenue of $6.7 billion. The Corporation's asset mix is approximately 96% regulated (70% electric, 26% gas), with the remaining 4% comprised of long-term contracted hydroelectric operations. The Corporation's regulated utilities serve more than 3 million customers across Canada and in the United States and the Caribbean. In 2015 the Corporation's electricity distribution systems met a combined peak demand of 9,705 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,323 terajoules.
The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are primarily 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; and (vi) regulatory lag in the case of a historical test year. 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.
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 generation assets, which are 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 summary describes the operations included in each of the Corporation's reportable segments.
REGULATED UTILITIES
The Corporation's interests in regulated electric and gas utilities are as follows.
Regulated Electric & Gas Utilities - United States
- UNS Energy: Primarily comprised of Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), (collectively, the "UNS Utilities"), acquired by Fortis in August 2014.
TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility. TEP generates, transmits and distributes electricity to approximately 417,000 retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells wholesale electricity to other entities in the western United States.
UNS Electric is a vertically integrated regulated electric utility, which generates, transmits and distributes electricity to approximately 94,000 retail customers in Arizona's Mohave and Santa Cruz counties.
TEP and UNS Electric currently own generation resources with an aggregate capacity of 2,799 MW, including 54 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2015, approximately 43% of the generating capacity was fuelled by coal.
UNS Gas is a regulated gas distribution utility, serving approximately 152,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties. - Central Hudson: Central Hudson Gas & Electric Corporation ("Central Hudson") is a regulated transmission and distribution ("T&D") utility, serving approximately 300,000 electricity customers and 79,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The Company owns gas-fired and hydroelectric generating capacity totalling 64 MW.
Regulated Gas Utility - Canadian
FortisBC Energy: Primarily includes FortisBC Energy Inc. ("FortisBC Energy" or "FEI") and, prior to December 31, 2014, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company. FEI is the largest distributor of natural gas in British Columbia, serving approximately 982,000 customers in more than 135 communities. Major areas served by the Company are the Lower Mainland, Vancouver Island and Whistler regions of British Columbia. FEI provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FEI's Southern Crossing pipeline, from Alberta.
Regulated Electric Utilities - Canadian
- FortisAlberta: FortisAlberta Inc. ("FortisAlberta") owns and operates the electricity distribution system in a substantial portion of southern and central Alberta, serving approximately 539,000 customers. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity.
- FortisBC Electric: Includes FortisBC Inc., an integrated electric utility operating in the southern interior of British Columbia, serving approximately 168,000 customers directly and indirectly. FortisBC Inc. owns four hydroelectric generating facilities with a combined capacity of 225 MW. Also included in the FortisBC Electric segment are the operating, maintenance and management services relating to the 493-MW Waneta hydroelectric generating facility owned by Teck Metals Ltd. and BC Hydro; the 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion"), owned by Fortis and Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"); the 149-MW Brilliant hydroelectric plant and the 120-MW Brilliant hydroelectric expansion plant, both owned by CPC/CBT; and the 185-MW Arrow Lakes hydroelectric plant owned by CPC/CBT.
- Eastern Canadian: Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited ("Maritime Electric") and FortisOntario Inc. ("FortisOntario"). Newfoundland Power is an integrated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador, serving approximately 262,000 customers. Newfoundland Power has an installed generating capacity of 139 MW, of which 97 MW is hydroelectric generation. Maritime Electric is an integrated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI"), serving approximately 78,000 customers. Maritime Electric also maintains on-Island generating facilities with a combined capacity of 150 MW. FortisOntario provides integrated electric utility service to approximately 65,000 customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. FortisOntario's operations are primarily comprised of Canadian Niagara Power Inc. ("Canadian Niagara Power"), Cornwall Street Railway, Light and Power Company, Limited ("Cornwall Electric") and Algoma Power Inc. ("Algoma Power").
Regulated Electric Utilities - Caribbean
The Regulated Electric Utilities - Caribbean segment includes the Corporation's approximate 60% controlling ownership interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities") (December 31, 2014 - 60%), Fortis Turks and Caicos, and the Corporation's 33% equity investment in Belize Electricity Limited ("Belize Electricity"). Caribbean Utilities is an integrated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands, serving approximately 28,000 customers. The Company has an installed diesel-powered generating capacity of 132 MW. Caribbean Utilities is a public company traded on the Toronto Stock Exchange ("TSX") (TSX:CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities serving approximately 14,000 customers on certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 82 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.
NON-REGULATED - FORTIS GENERATION
Fortis Generation is primarily comprised of long-term contracted generation assets in British Columbia and Belize. Generating assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion. Construction of the Waneta Expansion was completed in April 2015 and the output is sold to BC Hydro and FortisBC Electric under 40-year contracts. The Corporation's 51% controlling ownership interest in the Waneta Expansion is conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest.
Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW. All of the output of these facilities is sold to Belize Electricity under 50-year power purchase agreements ("PPAs") expiring in 2055 and 2060. The hydroelectric generation operations in Belize are conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL") under a franchise agreement with the Government of Belize ("GOB").
As at December 31, 2015, the 16-MW run-of-river Walden hydroelectric generating facility has been classified as held for sale.
In June 2015 and July 2015 the Corporation sold its non-regulated generation assets in Upstate New York and Ontario, respectively.
NON-REGULATED - NON-UTILITY
The Non-Utility segment previously included Fortis Properties Corporation ("Fortis Properties") and Griffith Energy Services, Inc. ("Griffith"). Fortis Properties completed the sale of its commercial real estate assets in June 2015 and its hotel assets in October 2015. For further information, refer to the "Significant Items" section of this MD&A. Griffith was sold in March 2014.
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.
CORPORATE STRATEGY
The principal business of Fortis is the ownership and operation of regulated electric and gas utilities. The Corporation remains focused on being a leader in the North American utility industry and its strategic vision is guided by the goals of delivering long-term profitable growth and building shareholder value. Earnings per common share and total shareholder return are the primary measures of financial performance.
Over the 10-year period ended December 31, 2015, earnings per common share of Fortis grew at a compound annual growth rate of 4.6%, on an adjusted basis. Over the same period, Fortis delivered an average annualized total return to shareholders of 8.2%, exceeding the S&P/TSX Capped Utilities and S&P/TSX Composite Indices, which delivered average annualized performance of 4.6% and 7.4%, respectively, over the same period.
The Corporation's first priority remains the continued profitable expansion of existing operations. Management remains focused on executing the consolidated capital program and pursuing additional investment opportunities within existing service territories. Fortis has also demonstrated its ability to acquire additional regulated utilities in Canada and the United States. The Corporation's standalone operating model and financial strength, driven by a strong balance sheet and investment-grade credit ratings, positions it well for future investment opportunities in existing and new franchise areas.
KEY TRENDS, RISKS AND OPPORTUNITIES
Pending Acquisition of ITC Holdings Corp.: On February 9, 2016, Fortis and ITC Holdings Corp. ("ITC") (NYSE:ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. For details on the Acquisition, including transaction details, strategic rationale and acquisition financing, refer to the "Subsequent Event" section of this MD&A, and for a discussion of risks associated with the Acquisition, refer to the "Business Risk Management - Risks Associated with the Acquisition of ITC" section of this MD&A.
Electric Utility Industry Developments: The North American electric utility industry has changed significantly over the past several years. The most notable changes include a continued focus on clean energy and energy conservation initiatives, while balancing technology advancements and changes in customer needs. At the same time, the continued low interest rate environment and decrease in world oil and gas prices are having significant impacts on the North American economy. Notwithstanding the changes occurring in the utility industry, safety, reliability and serving customers at the lowest reasonable cost remain at the forefront of the utility industry's focus.
Government and regulatory policy in Canada and the United States is being directed at environmental protection and energy efficiency. The increasing availability of cleaner sources of power generation are driving new environmental regulation designed to eliminate or reduce dependence on traditional sources of electricity power generation, such as coal. The availability of cheaper, cleaner burning natural gas, as well as growing accessibility of renewable or alternative energy sources like solar are encouraging governments to deploy aggressive targets for the removal of high carbon emission sources of energy. Reaching these targets will require the shutdown of certain high carbon emission generating plants earlier than planned, which is an issue that utilities and regulators need to address. These environmental regulations are, however, expected to create additional investment opportunities in renewable power generation and related energy infrastructure. Fortis' regulated utilities are actively involved in pursuing these opportunities.
Technological development, particularly in the area of distributed generation, is playing a significant role in the transformation of the utility industry. Although distributed generation customers remain connected to the electrical system and benefit from that connection, they avoid paying much of the fixed operating and maintenance costs because they can offset a portion of their volumetric energy usage with their own systems. This results in an increasing amount of utility costs that are ultimately shifted to other customers. The declining cost of certain types of distributed generation technologies, together with government subsidization, is encouraging increased adoption by customers. Not only does this expose the utility to declining revenue because of a decrease in energy sales, the rate structure serves to shift an increasing burden for these costs on those customers that do not have distributed generation, such as rooftop solar. Traditional rate designs have not been structured to ensure fairness among all customers, which is a focus for utilities and regulators. Fortis, through its subsidiaries, is working with its regulators to address these rate design issues for its customers.
Despite the challenges facing the utility industry, Fortis is well positioned to meet these headwinds and capitalize on any resulting opportunities. Its decentralized structure and customer focused business culture will support the efforts required to both meet evolving customer expectations and to work with policy makers and regulators on solutions that are financially sustainable for the utilities. Leveraging those relationships to get out in front of these evolving challenges will be essential to meeting the industry challenges.
Natural Gas Opportunities: FortisBC Energy continues to pursue opportunities in British Columbia related to gas infrastructure. The combination of an abundant supply of natural gas, low costs for natural gas and supportive government policy are generating new interest for large industrial customers and niche liquefied natural gas ("LNG") producers to utilize FortisBC Energy's gas system.
In 2013 the Government of British Columbia issued an Order in Council announcing the exemption of FEI's Tilbury LNG facility expansion ("Tilbury Expansion") from regulatory review. The Tilbury Expansion is well underway and will increase LNG production and storage capabilities, and is expected to be in service around the end of 2016. Since this announcement, there has been considerable interest for LNG supply from the Pacific Northwest, Hawaii, Alaska and international markets. In 2014 the Government of British Columbia issued a second Order in Council amending directions to the regulator regarding the Tilbury Expansion. The revisions set out a number of requirements for the regulator, including the consideration of a further expansion of the Tilbury site that would include additional liquefaction.
Traditionally, the majority of natural gas production in northern British Columbia has served the provincial and Pacific Northwest markets via the Westcoast (Spectra) system. However, to realize the full potential of British Columbia shale gas opportunities, additional capacity to connect to markets will have to be developed. FortisBC Energy continues to explore pipeline investment opportunities that include expansion of their existing distribution system to supply natural gas to a prospective LNG export facility, as well as to expand capacity on their Southern Crossing transmission pipeline. Specifically, FortisBC Energy is pursuing a potential pipeline expansion to the proposed Woodfibre LNG site in British Columbia. The Woodfibre LNG site is a former paper mill site located near Squamish, British Columbia. The Company has an opportunity to expand its gas pipeline and increase compression to deliver natural gas to this site.
For further information on the Corporation's natural gas investment opportunities, refer to the "Liquidity and Capital Resources - Additional Investment Opportunities" section of this MD&A.
Regulation: The Corporation's key business risk is regulation. Each of the Corporation's nine utilities is subject to regulation by the regulatory body in its respective operating jurisdiction. Relationships with the regulatory authorities are managed at the local utility level.
Commitment by the Corporation's utilities to provide safe and reliable service, operational excellence and promote positive customer and regulatory relations is important to ensure supportive regulatory relationships and obtain full cost recovery and competitive returns for the Corporation's shareholders.
Central Hudson began operating under a new three-year rate order in mid-2015. In November 2015 TEP 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. 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 increased from 43.5% to approximately 50%. The application also addresses 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. In May 2015 UNS Electric filed a similar GRA requesting new retail rates effective May 1, 2016, using 2014 as a historical test year. The nature of UNS Electric's application was similar to that of TEP.
The Corporation's regulatory calendar for its utilities in Canada continues to be extensive. Newfoundland Power recently filed a GRA for 2016 and FortisBC Energy, the benchmark utility in British Columbia, filed its application to review cost of capital for 2016. In Alberta, while the regulator issued decisions on outstanding generic cost of capital proceedings and capital tracker applications early in 2015, it has initiated a generic cost of capital proceeding for 2016 and 2017, which includes FortisAlberta.
For a further discussion of the nature of regulation and material regulatory decisions and applications and regulatory risk, refer to the "Regulatory Highlights" and "Business Risk Management" sections of this MD&A.
Capital Expenditure Program and Rate Base Growth: The Corporation's regulated midyear rate base for 2015 was $16.4 billion. Over the five-year period through 2020, excluding the pending acquisition of ITC, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to almost $21 billion in 2020 and produce a five-year compound annual growth rate in rate base of approximately 5%. Fortis expects this capital investment to support growth in earnings and dividends.
For further information on the Corporation's consolidated capital expenditure program and rate base of its regulated utilities, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.
Access to Capital and Liquidity: The Corporation's regulated utilities require ongoing access to long-term capital to fund investments in infrastructure necessary to provide service to customers. Long-term capital required to carry out the utility capital expenditure programs is mostly obtained at the regulated utility level. The regulated utilities usually issue debt at terms ranging between 5 and 40 years. As at December 31, 2015, almost 90% of the Corporation's consolidated long-term debt, excluding borrowings under long-term committed credit facilities, had maturities beyond five years. Management expects consolidated fixed-term debt maturities and repayments to average approximately $260 million annually over the next five years.
To help ensure uninterrupted access to capital and sufficient liquidity to fund capital programs and working capital requirements, the Corporation and its subsidiaries have approximately $3.6 billion in credit facilities, of which approximately $2.4 billion was unused as at December 31, 2015. Based on current credit ratings and conservative capital structures, the Corporation and its regulated utilities expect to continue to have reasonable access to long-term capital in 2016.
The Corporation has significant financing requirements associated with the pending acquisition of ITC. Refer to the "Business Risk Management - Risks Associated with the Acquisition of ITC" and "Subsequent Event" sections of this MD&A.
Dividend Increases: Dividends paid per common share increased to $1.40 in 2015. During 2015 Fortis increased its quarterly dividend per common share over 17% to $0.375 per quarter, or $1.50 on an annualized basis. This continues the Corporation's record of raising its annualized dividend to common shareholders for 42 consecutive years, the record for a public corporation in Canada.
Fortis also announced dividend guidance, targeting annual dividend per common share growth through 2020 of 6% based on a 2016 dividend of $1.50. This guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at its utilities, the successful execution of its $9 billion five-year capital expenditure plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of assets and record of operational excellence. The pending acquisition of ITC further supports this dividend guidance.
SIGNIFICANT ITEMS IN 2015
Pending Acquisition of Aitken Creek Gas Storage Facility: In December 2015 Fortis, through an indirect wholly owned subsidiary, entered into a definitive share purchase and sale agreement with Chevron Canada Properties Ltd. to acquire its share of the Aitken Creek Gas Storage Facility ("Aitken Creek") for approximately US$266 million, subject to customary closing conditions and adjustments. Aitken Creek is the largest gas storage facility in British Columbia with a total working gas capacity of 77 billion cubic feet and is an integral part of Western Canada's natural gas transmission network. The acquisition is subject to regulatory approval and is expected to close in the first half of 2016. The net cash purchase price is expected to be initially financed with borrowings under the Corporation's credit facility. In December 2015 the Corporation paid a deposit of US$29 million related to the transaction.
Sale of Commercial Real Estate and Hotel Assets: 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 an after-tax gain of approximately $109 million, net of expenses. As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering.
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 an after-tax loss of approximately $8 million, which reflects an impairment loss and expenses associated with the sale transaction.
Net proceeds from the sales were used by the Corporation to repay credit facility borrowings, the majority of which were used to finance a portion of the acquisition of UNS Energy.
Sale of Non-Regulated Generation Assets in New York and Ontario: 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 an after-tax gain of approximately $27 million (US$22 million), net of expenses and foreign exchange impacts.
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 an after-tax gain of approximately $5 million.
Settlement of Belize Electricity Expropriation Matters: In August 2015 the Corporation agreed to terms of a settlement with the GOB regarding the expropriation of the Corporation's approximate 70% interest in Belize Electricity in June 2011. The terms of the settlement included a one-time US$35 million cash payment to Fortis from the GOB and an approximate 33% equity investment in Belize Electricity. As a result of the settlement, the Corporation recognized an approximate $9 million loss.
| SUMMARY FINANCIAL HIGHLIGHTS |
| For the Years Ended December 31 | 2015 | 2014 | Variance | |
| Net Earnings Attributable to Common Equity Shareholders ($ millions) | 728 | 317 | 411 | |
| Basic Earnings per Common Share ($) | 2.61 | 1.41 | 1.20 | |
| Diluted Earnings per Common Share ($) | 2.59 | 1.40 | 1.19 | |
| Weighted Average Number of Common Shares Outstanding (millions) | 278.6 | 225.6 | 53.0 | |
| Cash Flow from Operating Activities ($ millions) | 1,673 | 982 | 691 | |
| Dividends Paid per Common Share ($) | 1.40 | 1.28 | 0.12 | |
| Dividend Payout Ratio (%) | 53.6 | 90.8 | (37.2 | ) |
| Return on Average Book Common Shareholders' Equity (%) (1) | 9.8 | 5.4 | 4.4 | |
| Total Assets ($ billions) | 28.8 | 26.2 | 2.6 | |
| Gross Capital Expenditures ($ billions) | 2.2 | 1.7 | 0.5 | |
| Public Preference Share Offering ($ billions) | - | 0.6 | (0.6 | ) |
| Convertible Debenture Offering ($ billions) | - | 1.8 | (1.8 | ) |
| Long-Term Debt Offerings ($ billions) | 1.0 | 1.2 | (0.2 | ) |
| (1) | Return on average book common shareholders' equity is a non-US GAAP measure and is defined as net earnings attributable to common equity shareholders divided by the average of opening and closing consolidated shareholders' equity, excluding preference shares and non-controlling interests. Return on average book common shareholders' equity is referred to by users of the Corporation's consolidated financial statements in evaluating the results of operations. |
Net Earnings Attributable to Common Equity Shareholders: Fortis achieved net earnings attributable to common equity shareholders of $728 million in 2015 compared to $317 million in 2014. On an adjusted basis, net earnings attributable to common equity shareholders for 2015 were $589 million, an increase of $195 million, or almost 50%, over 2014. Results for both years were impacted by non-recurring or adjusting items, which are detailed in the "Consolidated Results of Operations" section of this MD&A. The increase in adjusted net earnings attributable to common equity shareholders was driven by a full year's contribution from UNS Energy, which was acquired in mid-August 2014, earnings contribution from the Waneta Expansion, which came online in early April 2015, rate base growth associated with capital expenditures and growth in the number of customers at FortisAlberta, a higher allowance for funds used during construction ("AFUDC") at FortisBC Energy, the resetting of customer rates at Central Hudson, effective July 1, 2015, and the continued strength of the US dollar relative to the Canadian dollar. Earnings growth was tempered by an increase in Corporate expenses and lower earnings contribution due to the sale of the commercial real estate and hotel assets.
Basic Earnings per Common Share: Basic earnings per common share were $2.61 in 2015 compared to $1.41 in 2014. On an adjusted basis, as noted above, basic earnings per common share were $2.11 for 2015, an increase of $0.36 over 2014. The increase was driven by higher adjusted earnings per common share, as discussed above, partially offset by an increase in the weighted average number of common shares outstanding.
A graph is available at the following address: http://media3.marketwire.com/docs/basicearnings1.pdf
Cash Flow from Operating Activities: Cash flow from operating activities was $1,673 million for 2015, an increase of $691 million, or 70%, over 2014. The increase was driven by higher cash earnings, mainly due to the factors noted above, and favourable changes in working capital.
A graph is available at the following address: http://media3.marketwire.com/docs/cashflow1.pdf
Dividends: Dividends paid per common share increased to $1.40 in 2015, 9.0% higher than $1.28 in 2014. During 2015 Fortis increased its quarterly dividend per common share over 17% to $0.375 per quarter. The Corporation's dividend payout ratio was 53.6% in 2015 compared to 90.8% in 2014. On an adjusted basis, the dividend payout ratio was 66.4% in 2015 compared to 73.1% in 2014.
A graph is available at the following address: http://media3.marketwire.com/docs/dividen1.pdf
Return on Average Book Common Shareholders Equity: The return on average book common shareholders' equity for 2015 was 9.8% compared to 5.4% for 2014. On an adjusted basis, the return on average book common shareholders' equity for 2015 was 7.9%, compared to 6.8% for 2014.
Total Assets: Total assets increased 9.9% to approximately $28.8 billion at the end of 2015 compared to approximately $26.2 billion at the end of 2014. The increase reflects favourable foreign exchange on the translation of US dollar-denominated assets and continued investment in energy infrastructure, driven by capital spending at the regulated utilities, partially offset by the sale of commercial real estate and hotel assets in 2015.
A graph is available at the following address: http://media3.marketwire.com/docs/totalasset1.pdf
Gross Capital Expenditures: Consolidated capital expenditures, before customer contributions, were $2.2 billion in 2015 compared to $1.7 billion in 2014. The increase was driven by a full year contribution from UNS Energy and higher capital spending at most of the Corporation's regulated utilities, partially offset by lower non-regulated capital expenditures due to the completion of the Waneta Expansion and the sale of commercial real estate and hotel assets. For a detailed discussion of the Corporation's consolidated capital expenditure program, refer to the "Liquidity and Capital Resources - Capital Expenditure Program" section of this MD&A.
Long-Term Capital: The Corporation's regulated utilities raised approximately $1 billion in long-term debt in 2015, largely in support of energy infrastructure investment and regularly scheduled debt repayments.
Fortis completed the sale of $1.8 billion convertible debentures in 2014 to finance a portion of the acquisition of UNS Energy. In October 2014 approximately 58.2 million common shares of Fortis were issued on conversion of the debentures. In September 2014 Fortis issued 24 million First Preference Shares, Series M for gross proceeds of $600 million. The net proceeds were also used to finance a portion of the acquisition of UNS Energy. The Corporation and its regulated utilities raised approximately $1.2 billion in long-term debt in 2014.
For further information, refer to the "Liquidity and Capital Resources - Summary of Consolidated Cash Flows" section of this MD&A.
| CONSOLIDATED RESULTS OF OPERATIONS |
| Years Ended December 31 | ||||||
| ($ millions) | 2015 | 2014 | Variance | |||
| Revenue | 6,727 | 5,401 | 1,326 | |||
| Energy Supply Costs | 2,561 | 2,197 | 364 | |||
| Operating Expenses | 1,864 | 1,493 | 371 | |||
| Depreciation and Amortization | 873 | 688 | 185 | |||
| Other Income (Expenses), Net | 187 | (25 | ) | 212 | ||
| Finance Charges | 553 | 547 | 6 | |||
| Income Tax Expense | 223 | 66 | 157 | |||
| Earnings From Continuing Operations | 840 | 385 | 455 | |||
| Earnings From Discontinued Operations, Net of Tax | - | 5 | (5 | ) | ||
| Net Earnings | 840 | 390 | 450 | |||
| Net Earnings Attributable to: | ||||||
| Non-Controlling Interests | 35 | 11 | 24 | |||
| Preference Equity Shareholders | 77 | 62 | 15 | |||
| Common Equity Shareholders | 728 | 317 | 411 | |||
| Net Earnings | 840 | 390 | 450 | |||
Revenue
The increase in revenue was driven by the acquisition of UNS Energy in August 2014. Favourable foreign exchange associated with the translation of US dollar-denominated revenue, contribution from the Waneta Expansion and higher base electricity rates at the Canadian Regulated Electric Utilities also contributed to the increase. The increase was partially offset by the flow through in customer rates of lower energy supply costs at FortisBC Energy, Central Hudson and the Caribbean Regulated Electric Utilities, and a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively.
Energy Supply Costs
The increase in energy supply costs was primarily due to the acquisition of UNS Energy and unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs. The increase was partially offset by lower commodity costs at FortisBC Energy, Central Hudson and the Caribbean Regulated Electric Utilities.
Operating Expenses
The increase in operating expenses was primarily due to the acquisition of UNS Energy, unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases. The increase was partially offset by a decrease in non-utility operating expenses due to the sale of commercial real estate and hotel assets, and lower Corporate retirement expenses.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to the acquisition of UNS Energy and continued investment in energy infrastructure at the Corporation's regulated utilities.
Other Income (Expenses), Net
The increase in other income, net of expenses, was driven by gains on the sale of commercial real estate and non-regulated generation assets in 2015, compared to acquisition-related expenses associated with UNS Energy in 2014. The increase was partially offset by a loss associated with the sale of hotel assets in 2015.
Finance Charges
The increase in finance charges was primarily due to the acquisition of UNS Energy, including interest expense on debt issued to complete the financing of the acquisition, and unfavourable foreign exchange associated with the translation of US-dollar denominated interest expense. The increase was partially offset by lower interest on convertible debentures. Approximately $72 million ($51 million after tax) in interest expense was recognized in 2014 associated with convertible debentures issued to finance a portion of the acquisition of UNS Energy. In October 2014 the convertible debentures were substantially all converted into common shares of the Corporation.
Income Tax Expense
The increase in income tax expense was primarily due to higher earnings before income taxes, driven by the acquisition of UNS Energy and gains on the sale of commercial real estate and non-regulated generation assets in 2015, and a higher effective income tax rate, mainly due to the combined federal and state income tax rate at UNS Energy.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share
Net earnings attributable to common equity shareholders were impacted by a number of non-recurring or non-operating items. These items, referred to as adjusting items, are reconciled below and discussed in the segmented results of operations for the respective reporting segments. Management believes that adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share provide useful information to investors and shareholders as they provide increased transparency and predictive value. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.
| Non-US GAAP Reconciliation | |||||||
| Years Ended December 31 | |||||||
| ($ millions, except for common share data) | 2015 | 2014 | Variance | ||||
| Net Earnings Attributable to Common Equity Shareholders | 728 | 317 | 411 | ||||
| Adjusting Items: | |||||||
| FortisAlberta - | |||||||
| Capital tracker revenue adjustment for 2013 and 2014 | (9 | ) | - | (9 | ) | ||
| Non-Regulated - Fortis Generation - | |||||||
| Gain on sale of generation assets | (32 | ) | - | (32 | ) | ||
| Non-Utility - | |||||||
| Gain on sale of commercial real estate assets | (109 | ) | - | (109 | ) | ||
| Loss on sale of hotel assets | 8 | - | 8 | ||||
| Earnings from discontinued operations | - | (5 | ) | 5 | |||
| Corporate and Other - | |||||||
| Foreign exchange gain | (13 | ) | (8 | ) | (5 | ) | |
| Loss on settlement of expropriation matters | 9 | - | 9 | ||||
| Interest expense on convertible debentures | - | 51 | (51 | ) | |||
| Acquisition-related expenses | 7 | 39 | (32 | ) | |||
| Adjusted Net Earnings Attributable to Common Equity Shareholders | 589 | 394 | 195 | ||||
| Adjusted Basic Earnings Per Common Share ($) | 2.11 | 1.75 | 0.36 | ||||
Adjusted Net Earnings Attributable to Common Equity Shareholders
The increase in adjusted net earnings attributable to common equity shareholders was driven by earnings contribution of $195 million at UNS Energy compared to $60 million for 2014. Earnings contribution of $22 million from the Waneta Expansion, which represents the Corporation's 51% controlling ownership interest, also contributed to the increase. Performance was driven by all of the Corporation's other regulated utilities, including rate base growth associated with capital expenditures and growth in the number of customers at FortisAlberta; a higher AFUDC at FortisBC Energy; and improved performance at Central Hudson under a new three-year rate order. Favourable foreign exchange impacts associated with US dollar-denominated earnings also increased earnings year over year. The increase in adjusted earnings was partially offset by higher preference share dividends and finance charges in the Corporate and Other segment, largely associated with the acquisition of UNS Energy, and lower earnings contribution from non-utility assets due to the sale of commercial real estate and hotel assets.
Adjusted Basic Earnings Per Common Share
The increase in adjusted earnings per common share was driven by accretion associated with the acquisition of UNS Energy, after considering the finance charges associated with the acquisition and the increase in the weighted average number of common shares outstanding, and contribution from the Waneta Expansion. Performance at all of the Corporation's other regulated utilities, as discussed above, and the impact of favourable foreign exchange also contributed to the increase. The increase was partially offset by an increase in Corporate expenses and lower earnings contribution from non-utility assets due to the sale of commercial real estate and hotel assets.
| SEGMENTED RESULTS OF OPERATIONS |
| Segmented Net Earnings Attributable to Common Equity Shareholders | ||||||
| Years Ended December 31 | ||||||
| ($ millions) | 2015 | 2014 | Variance | |||
| Regulated Electric & Gas Utilities - United States | ||||||
| UNS Energy | 195 | 60 | 135 | |||
| Central Hudson | 58 | 37 | 21 | |||
| 253 | 97 | 156 | ||||
| Regulated Gas Utility - Canadian | ||||||
| FortisBC Energy | 140 | 127 | 13 | |||
| Regulated Electric Utilities - Canadian | ||||||
| FortisAlberta | 138 | 103 | 35 | |||
| FortisBC Electric | 50 | 46 | 4 | |||
| Eastern Canadian | 62 | 60 | 2 | |||
| 250 | 209 | 41 | ||||
| Regulated Electric Utilities - Caribbean | 34 | 27 | 7 | |||
| Non-Regulated - Fortis Generation | 77 | 20 | 57 | |||
| Non-Regulated - Non-Utility | 114 | 28 | 86 | |||
| Corporate and Other | (140 | ) | (191 | ) | 51 | |
| Net Earnings Attributable to Common Equity Shareholders | 728 | 317 | 411 | |||
The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A.
REGULATED UTILITIES
The Corporation's primary business is the ownership and operation of regulated utilities. In 2015 earnings from regulated assets represented approximately 92% (2014 - 91%) of the Corporation's earnings from its operating segments (excluding Corporate and Other segment expenses), excluding the gains on sale of non-core assets. Total regulated assets represented 96% of the Corporation's total assets as at December 31, 2015 (December 31, 2014 - 93%).
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
Regulated Electric & Gas Utilities - United States earnings for 2015 were $253 million (2014 - $97 million), which represented approximately 37% (2014 - 21%) of the Corporation's total regulated earnings. Total segment assets were approximately $12.1 billion as at December 31, 2015 (December 31, 2014 - $9.9 billion), which represented approximately 44% of the Corporation's total regulated assets as at December 31, 2015 (December 31, 2014 - 40%).
A graph is available at the following address: http://media3.marketwire.com/docs/regu1.pdf
| UNS ENERGY |
| Financial Highlights (1) | ||
| Years Ended December 31 | 2015 | 2014 |
| Average US:CAD Exchange Rate (2) | 1.28 | 1.12 |
| Electricity Sales (gigawatt hours ("GWh")) | 15,366 | 5,646 |
| Gas Volumes (petajoules ("PJ")) | 13 | 5 |
| Revenue ($ millions) | 2,034 | 684 |
| Earnings ($ millions) | 195 | 60 |
| (1) | Financial results of UNS Energy are from August 15, 2014, the date of acquisition. |
| (2) | The reporting currency of UNS Energy is the US dollar. The average US:CAD exchange rate for 2014 is from the date of acquisition. |
Electricity Sales & Gas Volumes
Electricity sales were 15,366 gigawatt hours ("GWh") for 2015 compared to 14,560 GWh for the full year in 2014. The increase was primarily due to higher short-term wholesale electricity sales. The majority of short-term wholesale electricity sales is flowed through to customers and has no impact on earnings. Retail sales were comparable year over year.
Gas volumes of 13 petajoules ("PJ") for 2015 were comparable with the full year in 2014.
Revenue
Revenue was US$1,588 million for 2015 compared to US$1,560 million for the full year in 2014. The increase was primarily due to the flow through to customers of higher purchased power and fuel supply costs, higher transmission revenue, and higher wholesale electricity sales. On a Canadian dollar basis, revenue was also impacted by favourable foreign exchange.
Earnings
Earnings were US$152 million for 2015 compared to US$144 million for the full year in 2014, excluding the impact of acquisition-related expenses. The increase was primarily due to higher transmission revenue and a decrease in interest expense due to the expiry of leasing arrangements. The increase was partially offset by higher operating expenses. On a Canadian dollar basis, earnings were also impacted by favourable foreign exchange.
| CENTRAL HUDSON |
| Financial Highlights | |||
| Years Ended December 31 | 2015 | 2014 | Variance |
| Average US:CAD Exchange Rate (1) | 1.28 | 1.10 | 0.18 |
| Electricity Sales (GWh) | 5,132 | 5,075 | 57 |
| Gas Volumes (PJ) | 24 | 23 | 1 |
| Revenue ($ millions) | 880 | 821 | 59 |
| Earnings ($ millions) | 58 | 37 | 21 |
| (1) | The reporting currency of Central Hudson is the US dollar. |
Electricity Sales & Gas Volumes
The increase in electricity sales was mainly due to higher average consumption as a result of warmer temperatures in the summer, which increased the use of air conditioning and other cooling equipment. Gas volumes for 2015 were comparable with last year.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on revenue and earnings.
Revenue
The increase in revenue was driven by approximately $111 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. An increase in base electricity rates effective July 1, 2015 and the recovery from customers of previously deferred electricity costs also contributed to the increase in revenue. Additionally, revenue for the first half of 2015 was favourably impacted by energy efficiency incentives and higher gas revenue associated with a new gas delivery contract in late 2014. The increase was partially offset by the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices.
Earnings
The increase in earnings was primarily due to approximately $9 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, an increase in base electricity rates effective July 1, 2015, a new gas delivery contract implemented in late 2014, and energy efficiency incentives earned during the first half of 2015. The increase was partially offset by the impact of higher expenses during the two-year rate freeze period post acquisition, which ended on June 30, 2015.
REGULATED GAS UTILITY - CANADIAN
Regulated Gas Utility - Canadian earnings for 2015 were $140 million (2014 - $127 million), which represented approximately 21% of the Corporation's total regulated earnings (2014 - 28%). Total segment assets were approximately $6.0 billion as at December 31, 2015 (December 31, 2014 - $5.8 billion), which represented approximately 22% of the Corporation's total regulated assets as at December 31, 2015 (December 31, 2014 - 24%).
A graph is available at the following address: http://media3.marketwire.com/docs/regugas1.pdf
| FORTISBC ENERGY |
| Financial Highlights | ||||
| Years Ended December 31 | 2015 | 2014 | Variance | |
| Gas Volumes (PJ) | 186 | 195 | (9 | ) |
| Revenue ($ millions) | 1,295 | 1,435 | (140 | ) |
| Earnings ($ millions) | 140 | 127 | 13 |
Gas Volumes
The decrease in gas volumes was primarily due to lower average consumption in the first quarter as a result of warmer temperatures.
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 from those forecast to set customer gas rates do not materially affect earnings.
Revenue
The decrease in revenue was primarily due to a lower commodity cost of natural gas charged to customers and lower gas volumes. The decrease was partially offset by higher regulatory flow-through deferral amounts.
Earnings
The increase in earnings was mainly due to higher AFUDC, regulatory flow-through deferral amounts and operating cost savings, net of the earnings sharing mechanism. The increase was partially offset by a decrease in the allowed ROE and equity component of capital structure as a result of the amalgamation of FEVI and FEWI with FEI, effective December 31, 2014. For further details on the amalgamation, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
Regulated Electric Utilities - Canadian earnings for 2015 were $250 million (2014 - $209 million), which represented approximately 37% of the Corporation's total regulated earnings (2014 - 45%). Total segment assets were approximately $8.2 billion as at December 31, 2015 (December 31, 2014 - $7.7 billion), which represented approximately 30% of the Corporation's total regulated assets as at December 31, 2015 (December 31, 2014 - 32%).
A graph is available at the following address: http://media3.marketwire.com/docs/reguelect1.pdf
| FORTISALBERTA |
| Financial Highlights | ||||
| Years Ended December 31 | 2015 | 2014 | Variance | |
| Energy Deliveries (GWh) | 17,132 | 17,372 | (240 | ) |
| Revenue ($ millions) | 563 | 518 | 45 | |
| Earnings ($ millions) | 138 | 103 | 35 | |
Energy Deliveries
The decrease in energy deliveries was primarily due to lower average consumption by oil and gas customers as a result of low commodity prices for oil and gas, partially offset by higher average consumption by farm and irrigation, residential and commercial customers. Lower levels of precipitation, particularly in the third quarter, and warmer temperatures had a favorable impact on energy deliveries to farm and irrigation customers. Higher energy deliveries to residential and commercial customers due to customer growth were partially offset by lower average consumption due to warmer temperatures.
Revenue
As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
The increase in revenue was primarily due to the operation of the PBR formula, including an increase in customer rates based on a combined inflation and productivity factor of 1.49%, higher capital tracker revenue, growth in the number of customers, and higher revenue related to flow-through costs to customers. Revenue was also favourably impacted by a $9 million capital tracker revenue adjustment recognized in 2015 associated with 2013 and 2014, as a result of regulatory decisions. For further details on regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Earnings
The increase in earnings was primarily due to rate base growth associated with capital expenditures, growth in the number of customers, and the impact of a technical update on depreciation and amortization. Also contributing to the increase in earnings was capital tracker revenue of approximately $9 million recognized in 2015 associated with 2013 and 2014, as discussed above.
| FORTISBC ELECTRIC |
| Financial Highlights | ||||
| Years Ended December 31 | 2015 | 2014 | Variance | |
| Electricity Sales (GWh) | 3,116 | 3,179 | (63 | ) |
| Revenue ($ millions) | 360 | 334 | 26 | |
| Earnings ($ millions) | 50 | 46 | 4 | |
Electricity Sales
The decrease in electricity sales was primarily due to lower average consumption in the first and fourth quarters as a result of warmer temperatures.
Revenue
The increase in revenue was driven by increases in base electricity rates, mainly established to recover higher power purchase costs, and surplus capacity sales. Revenue was also favourably impacted by higher contribution from non-regulated operating, maintenance and management services associated with the Waneta Expansion. The increase was partially offset by lower electricity sales.
Earnings
The increase in earnings was primarily due to higher earnings from non-regulated operating, maintenance and management services, and rate base growth.
| EASTERN CANADIAN ELECTRIC UTILITIES |
| Financial Highlights | |||
| Years Ended December 31 | 2015 | 2014 | Variance |
| Electricity Sales (GWh) | 8,403 | 8,376 | 27 |
| Revenue ($ millions) | 1,033 | 1,008 | 25 |
| Earnings ($ millions) | 62 | 60 | 2 |
Electricity Sales
The increase in electricity sales was primarily due to customer growth in Newfoundland, as well as higher average consumption in PEI, mainly due to an increase in the number of customers using electricity for home heating. The increase was partially offset by lower electricity sales in Ontario, largely due to the loss of a commercial customer and lower average consumption by residential customers due to changes in temperatures.
Revenue
The increase in revenue was mainly due to the flow through in customer electricity rates of overall higher energy supply costs and electricity sales growth.
Earnings
The increase in earnings was primarily due to electricity sales growth and lower operating costs, mainly due to restoration efforts at Newfoundland Power following the loss of energy supply from Newfoundland and Labrador Hydro ("Newfoundland Hydro") and related power interruptions in January 2014, partially offset by higher depreciation expense.
REGULATED ELECTRIC UTILITIES - CARIBBEAN
Regulated Electric Utilities - Caribbean earnings for 2015 were $34 million (2014 - $27 million), which represented approximately 5% of the Corporation's total regulated earnings (2014 - 6%). Total segment assets were approximately $1.3 billion as at December 31, 2015 (December 31, 2014 - $1.1 billion), which represented approximately 4% of the Corporation's total regulated assets as at December 31, 2015 (December 31, 2014 - 4%).
A graph is available at the following address: http://media3.marketwire.com/docs/caribean.pdf
| Financial Highlights | |||
| Years Ended December 31 | 2015 | 2014 | Variance |
| Average US:CAD Exchange Rate (1) | 1.28 | 1.10 | 0.18 |
| Electricity Sales (GWh) | 802 | 771 | 31 |
| Revenue ($ millions) | 321 | 321 | - |
| Earnings ($ millions) | 34 | 27 | 7 |
| (1) | The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. |
Electricity Sales
The increase in electricity sales was primarily due to growth in the number of customers as a result of increased economic activity and overall warmer temperatures, which increased air conditioning load.
Revenue
Revenue was impacted by approximately $39 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, and electricity sales growth. The increase was largely offset by the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities.
Earnings
The increase in earnings was due to approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, electricity sales growth and higher capitalized interest at Caribbean Utilities. The increase was partially offset by higher depreciation. Equity income from Belize Electricity from the date of settlement in August 2015 was less than $1 million.
NON-REGULATED
| NON-REGULATED - FORTIS GENERATION |
| Financial Highlights | |||
| Years Ended December 31 | 2015 | 2014 | Variance |
| Energy Sales (GWh) | 844 | 407 | 437 |
| Revenue ($ millions) | 107 | 38 | 69 |
| Earnings ($ millions) | 77 | 20 | 57 |
A graph is available at the following address: http://media3.marketwire.com/docs/nonreg1.pdf
Energy Sales
The increase in energy sales was driven by the Waneta Expansion, which commenced production in early April 2015 and reported energy sales of 517 GWh in 2015. The increase was partially offset by decreased production in Belize due to lower rainfall and in Upstate New York and Ontario due to the sale of generation assets in mid 2015, lower rainfall, and generating units taken out of service for repairs.
Revenue
The increase in revenue was driven by the Waneta Expansion, which recognized revenue of $70 million in 2015, and approximately $4 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase was partially offset by decreased production in Belize, Upstate New York and Ontario.
Earnings
The increase in earnings was driven by the recognition of after-tax gains totalling approximately $32 million on the sale of generation assets in Upstate New York and Ontario in mid 2015, and earnings contribution of $22 million from the Waneta Expansion. Approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings and lower business development costs were partially offset by decreased production in Belize, Upstate New York and Ontario.
| NON-REGULATED - NON-UTILITY |
| Financial Highlights | ||||
| Years Ended December 31 | ||||
| ($ millions) | 2015 | 2014 | Variance | |
| Revenue | 171 | 249 | (78 | ) |
| Earnings | 114 | 28 | 86 | |
A graph is available at the following address: http://media3.marketwire.com/docs/nonregu2.pdf
Revenue
The decrease in revenue was primarily due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively.
Earnings
The increase in earnings was driven by a net after-tax gain of approximately $101 million on the sale of commercial real estate and hotel assets. The increase was partially offset by lower earnings contribution from the commercial real estate and hotel assets as a result of the sale and $5 million in earnings in 2014 associated with Griffith from normal operations to the date of sale in March 2014.
| CORPORATE AND OTHER |
| Financial Highlights | ||||||
| Years Ended December 31 | ||||||
| ($ millions) | 2015 | 2014 | Variance | |||
| Revenue | 24 | 31 | (7 | ) | ||
| Operating Expenses | 26 | 38 | (12 | ) | ||
| Depreciation and Amortization | 2 | 2 | - | |||
| Other Income (Expenses), Net | (8 | ) | (45 | ) | 37 | |
| Finance Charges | 94 | 154 | (60 | ) | ||
| Income Tax Recovery | (43 | ) | (79 | ) | 36 | |
| (63 | ) | (129 | ) | 66 | ||
| Preference Share Dividends | 77 | 62 | 15 | |||
| Net Corporate and Other Expenses | (140 | ) | (191 | ) | 51 | |
Net Corporate and Other expenses were impacted by the following items.
- A foreign exchange gain of $13 million in 2015 compared to $8 million in 2014, 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, which was included in other income;
- A loss of approximately $9 million in 2015 on settlement of expropriation matters related to the Corporation's investment in Belize Electricity, which was included in other income, net of expenses;
- Acquisition-related expenses of $10 million ($7 million after tax) in 2015 associated with the pending acquisition of ITC, which were included in other income;
- Finance charges of $72 million ($51 million after tax) in 2014 associated with the convertible debentures issued to finance a portion of the acquisition of UNS Energy; and
- Other expenses of approximately $58 million ($39 million after tax) in 2014 related to the acquisition of UNS Energy.
Excluding the above-noted items, net Corporate and Other expenses were $137 million for 2015 compared to approximately $109 million for 2014. The increase in net Corporate and Other expenses was primarily due to higher preference share dividends and finance charges, and a decrease in revenue. The increase was partially offset by lower operating expenses.
The increase in preference share dividends and finance charges was primarily due to the acquisition of UNS Energy. Finance charges were also impacted by no longer capitalizing interest upon completion of the Waneta Expansion and unfavourable foreign exchange associated with the translation of US-dollar denominated interest expense.
The decrease in revenue was primarily due to a decrease in related-party interest income, mainly due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively.
The decrease in operating expenses was primarily due to lower retirement expenses. Retirement expenses of approximately $13 million ($11 million after tax) were recognized in 2014 compared to approximately $2 million ($1 million after tax) in 2015. The decrease in operating expenses was partially offset by a $3 million ($2 million after tax) corporate donation recognized in 2015.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated electric and gas utilities are summarized as follows.
| NATURE OF REGULATION | ||||||||||
| Allowed Returns (%) | Significant Features | |||||||||
| Regulated Utility |
Regulatory Authority |
Allowed Common Equity (%) |
2014 |
2015 |
2016 |
Future or Historical Test Year Used to Set Customer Rates |
||||
| ROE | ||||||||||
| TEP |
ACC |
43.5 |
10.00 |
10.00 |
10.00 |
COS/ROE (1) |
||||
| UNS Electric | ACC | 52.6(2) | 9.50 | 9.50 | 9.50(2) | ROEs established by the ACC | ||||
| UNS Gas | ACC | 50.8 | 9.75 | 9.75 | 9.75 | |||||
| Historical Test Year | ||||||||||
| Central | New York State | 48 | 10.00 | 10.00/9.00 (3) | 9.00 | COS/ROE | ||||
| Hudson |
Public Service Commission ("PSC") |
|
|
|
|
Earnings sharing mechanism ROE established by the PSC |
||||
| Future Test Year | ||||||||||
| FEI |
British Columbia Utilities Commission ("BCUC") |
38.5(2) |
8.75 |
8.75 |
8.75(2) |
COS/ROE PBR mechanism for 2014 through 2019 |
||||
| FEVI | BCUC | 41.5(4) | 9.25 | n/a(4) | n/a(4) | ROEs established by the BCUC | ||||
| FEWI | BCUC | 41.5(4) | 9.50 | n/a(4) | n/a(4) | |||||
| 2013 test year with 2014 through 2019 | ||||||||||
| rates set using PBR mechanism | ||||||||||
| FortisBC | BCUC | 40(2) | 9.15 | 9.15 | 9.15(2) | COS/ROE | ||||
| Electric |
|
|
|
|
|
PBR mechanism for 2014 through 2019 |
||||
| ROE established by the BCUC | ||||||||||
| 2013 test year with 2014 through 2019 | ||||||||||
| rates set using PBR mechanism | ||||||||||
| FortisAlberta | Alberta Utilities | 40(2) | 8.30 | 8.30 | 8.30(2) | COS/ROE | ||||
| |
Commission ("AUC") |
|
|
|
|
PBR mechanism for 2013 through 2017 with capital tracker account and other supportive features |
||||
| ROE established by the AUC | ||||||||||
| |
|
|
|
|
|
2012 test year with 2013 through 2017 rates set using PBR mechanism |
||||
| Newfoundland | Newfoundland and | 45(2) | 8.80 +/- | 8.80 +/- | 8.80 +/- (2) | COS/ROE | ||||
| Power |
Labrador Board of Commissioners of Public Utilities |
|
50 bps |
50 bps |
50 bps |
ROE established by the PUB |
||||
| ("PUB") | Future Test Year | |||||||||
| Maritime | Island Regulatory | 40(2) | 9.75 | 9.75 | 9.35(2) | COS/ROE | ||||
| Electric |
and Appeals Commission ("IRAC") |
|
|
|
|
ROE established by the PEI Energy Accord in 2014 and 2015. ROE in 2016 to be established by IRAC |
||||
| Future Test Year | ||||||||||
| FortisOntario | Ontario Energy | 40 | 8.93 - | 8.93 - | 8.93 - | COS/ROE (5) | ||||
| |
Board |
|
9.85 |
9.30 |
9.30 |
Future test year and incentive regulation rate-setting mechanism |
||||
| ROA | ||||||||||
| Caribbean | Electricity Regulatory | N/A | 7.00 - | 7.25 - | 6.75 - | COS/ROA | ||||
| Utilities |
Authority |
|
9.00 |
9.25 |
8.75 |
Rate-cap adjustment mechanism based on published consumer price indices |
||||
| Historical Test Year | ||||||||||
| Fortis Turks and Caicos |
|
Government of the Turks and Caicos |
|
N/A |
15.00 - 17.50(6) |
15.00 - 17.50(6) |
|
15.00 - 17.50(6) |
COS/ROA |
|
| Islands | Historical Test Year | |||||||||
| (1) | Additionally, allowed ROEs are adjusted for the fair value of rate base as required under the laws of the State of Arizona. |
| (2) | Interim and subject to change pending the outcome of regulatory proceedings effective January 1, 2016 for FortisAlberta, FEI and FortisBC Electric; May 1, 2016 for UNS Electric; July 1, 2016 for Newfoundland Power; and March 1, 2016 for Maritime Electric. |
| (3) | Allowed ROE of 10.0% with a 48% common equity component of capital structure to June 30, 2015. Allowed ROE of 9.00% with a 48% common equity component of capital structure effective July 1, 2015 through June 30, 2018. |
| As approved by the BCUC, effective December 31, 2014, FEVI and FEWI were amalgamated with FEI and, as a result, the allowed ROE and common equity component of capital structure for 2015 reverted to those of FEI. | |
| (5) | Cornwall Electric is subject to a rate-setting mechanism under a Franchise Agreement with the City of Cornwall, based on a price cap with commodity cost flow through. |
| (6) | Achieved ROAs at the utilities are significantly lower than those allowed under licences as a result of the inability, due to economic and political factors, to increase base customer electricity rates. |
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
The following summarizes the significant regulatory decisions and applications for the Corporation's regulated utilities for 2015.
UNS Energy
In November 2015 TEP, UNS Energy's largest utility, filed a GRA with the 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 include: (i) a base retail rate increase of US$110 million, or 12.0%, compared with adjusted test year revenue; (ii) a 7.34% return on original cost rate base of US$2.1 billion; (iii) a common equity component of capital structure of approximately 50%; (iv) a cost of equity of 10.35% and an average cost of debt of 4.32%; and (v) rate design changes that would reduce the reliance on volumetric sales to recover fixed costs, and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure increased from 43.5% to approximately 50%. In May 2015 UNS Electric filed a GRA requesting new retail rates to be effective May 1, 2016, using 2014 as a historical test year. The nature of UNS Electric's GRA was similar to that of TEP. A decision on UNS Electric's application is expected in the third quarter of 2016 and TEP's application is expected in the fourth quarter of 2016.
Central Hudson
Three-Year Rate Order
In June 2015 the PSC issued a Rate Order for Central Hudson covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson invested approximately US$225 million in energy infrastructure during the two-year delivery rate freeze period ended June 30, 2015. The approved Rate Order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure. The Rate Order includes capital investments of approximately US$490 million during the three-year period targeted at making the electric and gas systems stronger.
The approved Rate Order includes full cost recovery of electric and natural gas commodity costs and continuation of certain mechanisms, including revenue decoupling and earnings sharing mechanisms. In the approved earnings sharing mechanism, the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Earnings in excess of 100 basis points above the allowed ROE are shared primarily with the customer. In addition, the Rate Order includes a major storm reserve for electric operations and provides for continuation of recovery of various operating expenses, including environmental site investigation and remediation costs. To the extent that Central Hudson receives gas delivery revenue associated with a new contract implemented in late 2014, associated revenue is being used to mitigate future gas customer rate increases, effective July 1, 2015.
Reforming the Energy Vision
In 2014 the PSC issued an order instituting a proceeding to reform New York State's electricity industry and regulatory practices ("Reforming the Energy Vision"). The initiative seeks to further a number of policy objectives and seeks to determine the appropriate role of electric distribution utilities in furthering these objectives, as well as considering regulatory changes to better align utility interest with energy policy objectives. In 2015 Central Hudson continued to fully participate in this proceeding. The outcome of Reforming the Energy Vision cannot be determined at this time and it could impact the scope of regulated utilities in New York State.
FortisBC Energy and FortisBC Electric
Multi-Year PBR Plans
In September 2014 the BCUC issued its decisions on FEI and FortisBC Electric's Multi-Year PBR Plans for 2014 through 2019. The approved PBR Plans incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FEI and 1.03% for FortisBC Electric each year. The approved PBR Plans also include a 50%/50% sharing of variances from the formula-driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FEI and FortisBC Electric maintain service levels. It also sets out the requirements for an annual review process which will provide a forum for discussion between the utilities and interested parties regarding current performance and future activities.
In May 2015 and June 2015, the BCUC issued its decisions on FEI and FortisBC Electric's 2015 rates in compliance with the PBR decisions issued in September 2014. The decisions approved 2015 midyear rate base of approximately $3,661 million and $1,249 million for FEI and FortisBC Electric, respectively, and approved customer rate increases for 2015 of 0.7% and 4.2% over 2014 rates, respectively.
In December 2015 the BCUC issued its decisions on FEI and FortisBC Electric's 2016 rates. The decisions approved 2016 midyear rate base of approximately $3,693 million and $1,286 million for FEI and FortisBC Electric, respectively, and approved customer rate increases for 2016 of 1.79% and 2.96% over 2015 rates, respectively.
Generic Cost of Capital Proceedings
A Generic Cost of Capital ("GCOC") Proceeding to establish the allowed ROE and capital structures for regulated utilities in British Columbia occurred from 2012 through 2014. FEI was designated as the benchmark utility and a BCUC decision established that the ROE for the benchmark utility would be set at 8.75% with a 38.5% common equity component of capital structure, both effective January 1, 2013 through December 31, 2015. The GCOC Proceeding reaffirmed for FortisBC Electric a risk premium over the benchmark utility of 40 basis points, resulting in an allowed ROE of 9.15% effective January 1, 2013 through December 31, 2015, and a common equity component of capital structure at 40%.
The BCUC decision directed FEI to file an application to review the 2016 benchmark utility ROE and common equity component of capital structure. 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. As FEI is the benchmark utility, the review of the application could also have an impact on FortisBC Electric. A decision on the application is expected in the second quarter of 2016.
FortisAlberta
Generic Cost of Capital Proceedings
In March 2015 the AUC issued its decision on the GCOC Proceeding in Alberta. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41%. The AUC also determined that it would not re-establish a formula-based approach to setting the allowed ROE at this time. Instead, the allowed ROE of 8.30% and common equity component of capital structure of 40% will remain in effect on an interim basis for 2016 and beyond. For regulated utilities in Alberta under PBR mechanisms, including FortisAlberta, the impact of the changes to the allowed ROE and common equity component of capital structure resulting from the GCOC Proceeding applies to the portion of rate base that is funded by capital tracker revenue only. For assets not being funded by capital tracker revenue, no revenue adjustment is required for the change in the allowed ROE and common equity component of capital structure, from that set in an earlier GCOC decision.
In April 2015 the AUC initiated a GCOC Proceeding to set the allowed ROE and capital structure for 2016 and 2017. While the AUC approved a request by utilities in Alberta to negotiate matters at issue in the GCOC Proceeding for 2016, a negotiated settlement was not reached and a 2016 and 2017 GCOC Proceeding commenced. A hearing is scheduled for June 2016 and a decision is expected before the end of 2016.
Capital Tracker Applications
The funding of capital expenditures during the PBR term is a material aspect of the PBR plan for FortisAlberta. The PBR plan provides a capital tracker mechanism to fund the recovery of costs associated with certain qualifying capital expenditures.
In March 2015 the AUC issued its decision related to FortisAlberta's 2013, 2014 and 2015 Capital Tracker Applications. The decision: (i) indicated that the majority of the Company's applied for capital trackers met the established criteria and were, therefore, approved for collection from customers; (ii) approved FortisAlberta's accounting test to determine qualifying K factor amounts; and (iii) confirmed certain inputs to be used in the accounting test, including the conclusion that the weighted average cost of capital be based on actual debt rates and the allowed ROE and capital structure approved in the GCOC Proceeding.
In September 2015 the AUC approved FortisAlberta's compliance filing related to the 2015 Capital Tracker Decision, substantially as filed. Capital tracker revenue of $17 million was approved for 2013 on an actual basis and capital tracker revenue of $42 million and $62 million was approved on a forecast basis for 2014 and 2015, respectively. FortisAlberta collected $15 million, $29 million and $62 million in 2013, 2014 and 2015, respectively, related to capital tracker expenditures.
In May 2015 FortisAlberta filed an application with the AUC seeking: (i) capital tracker revenue of $72 million for 2016 and $90 million for 2017; (ii) a reduction of $5 million to the 2014 capital tracker revenue to reflect actual capital expenditures; and (iii) approval of additional revenue related to capital tracker amounts that had not been fully approved in the 2015 Capital Tracker Decision. A hearing related to this proceeding concluded in October 2015, with a decision from the regulator expected in the first quarter of 2016.
FortisAlberta recognized capital tracker revenue of approximately $59 million in 2015, of which $9 million was related to updates to the 2013 and 2014 capital tracker approved amounts. The capital tracker revenue for 2015 of approximately $50 million incorporates an update for related 2015 capital expenditures as compared to the approved forecast reflected in current rates. This resulted in a deferral of $12 million of 2015 capital tracker revenue as a regulatory liability.
2016 Annual Rates Application
In December 2015 the regulator approved FortisAlberta's 2016 Annual Rates Application substantially as filed. The rates and riders, effective January 1, 2016, include an increase of approximately 4.6% to the distribution component of customer rates. This increase reflects: (i) a combined inflation and productivity factor of 0.9%; (ii) a K factor placeholder of $64 million, which is 90% of the depreciation and return associated with the 2016 forecast capital tracker expenditures as filed in the capital tracker applications, as discussed previously; and (iii) $17 million for adjustments to 2013, 2014 and 2015 capital tracker revenue as filed in the capital tracker compliance filing related to the 2015 capital tracker decision.
Utility Asset Disposition Matters
In previous decisions, the AUC made statements regarding cost responsibility for stranded assets and gains or losses related to extraordinary retirement of utility assets, which FortisAlberta and other Alberta utilities challenged as being incorrectly made. Stranded assets are generally understood to be utility assets no longer used to provide utility service as a result of extraordinary circumstances. The AUC's statements implied that the shareholder is responsible for the cost of stranded assets in a broader sense than that generally understood by regulated utilities and also conflicted with the Electric Utilities Act (Alberta). As a result, the utilities in Alberta had filed leave to appeal motions with the Court of Appeal of Alberta.
In September 2015 the Court of Appeal of Alberta issued a decision that dismissed the appeals of the utilities. The basis for the decision was that the AUC should be accorded deference for its conclusions in utility asset disposition matters. The decision by the Court of Appeal of Alberta has no immediate impact on FortisAlberta's financial position. However, the Company is exposed to the risk that unrecovered costs associated with utility assets subsequently deemed by the AUC to have been subject to an extraordinary retirement will not be recoverable from customers. In November 2015 the utilities in Alberta filed a leave to appeal motion with the Supreme Court of Canada, the outcome and timing of which is unknown.
Eastern Canadian Electric Utilities
In October 2015 Newfoundland Power filed a 2016/2017 GRA with the PUB to set customer rates effective July 1, 2016. The Company is proposing an overall average increase in electricity rates of 3.1%. The GRA will include a full review of Newfoundland Power's costs, including cost of capital. The application is currently under review by the PUB. A public hearing is scheduled to begin at the end of the first quarter of 2016 and a decision on the application is expected by the end of the second quarter of 2016.
In October 2015 Maritime Electric filed a GRA with the 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 PEI entered into a 2016 General Rate Agreement covering the three-year period from March 1, 2016 through February 28, 2019. The agreement, which is subject to regulatory approval, is generally consistent with the GRA filed in October 2015, however, reflects an allowed ROE capped at 9.35% on a maximum average common equity component of capital structure of 40%. Under the agreement, the typical customer electricity cost increase will be limited to a maximum of 2.3% annually.
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 | ||
| UNS Electric | GRA for 2016 | May 2015 | Third quarter of 2016 | ||
| Central Hudson | Reforming the Energy Vision | Not applicable | To be determined | ||
| FEI | 2016 Cost of Capital Application | October 2015 | Second quarter of 2016 | ||
| FortisAlberta | 2016/2017 Capital Tracker Application | May 2015 | First quarter of 2016 | ||
| 2016/2017 GCOC Proceeding | Not applicable | Second half of 2016 | |||
| Newfoundland Power | GRA for 2016/2017 | October 2015 | Second quarter of 2016 |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between December 31, 2015 and December 31, 2014.
| Significant Changes in the Consolidated Balance Sheets between December 31, 2015 and December 31, 2014 | ||
Balance Sheet Account |
Increase/ (Decrease) ($ millions) |
Explanation |
| Regulatory assets - current and long-term |
117 | The increase was mainly due to: (i) an increase in regulatory deferred income taxes, mainly at FortisAlberta; (ii) the impact of foreign exchange on the translation of US dollar-denominated regulatory assets; and (iii) the deferral of various other costs as permitted by the regulators. The above-noted increases were partially offset by a reduction in regulatory assets at Central Hudson due to the offsetting of certain regulatory account balances, as approved by the regulator, and a decrease in the deferral for employee future benefits. |
| Utility capital assets | 2,416 | The increase primarily related to utility capital expenditures and the impact of foreign exchange on the translation of US dollar-denominated utility capital assets, partially offset by depreciation and customer contributions. |
| Non-utility capital assets | (664) | The decrease was due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively. |
| Goodwill | 441 | The increase was due to the impact of foreign exchange on the translation of US dollar-denominated goodwill. |
| Short-term borrowings | 181 | The increase was mainly due to higher short-term borrowings at FortisBC Energy and FortisBC Electric, largely to finance utility capital expenditures. |
| Regulatory liabilities - current and long-term | 193 | The increase was mainly due to the impact of foreign exchange on the translation of US dollar-denominated regulatory liabilities and higher rate stabilization accounts at FortisBC Energy, partially offset by a reduction in regulatory liabilities at Central Hudson due to the offsetting of certain regulatory account balances, as approved by the regulator. |
| Long-term debt (including current portion) |
732 | The increase was primarily due to the issuance of long-term debt at the Corporation's regulated utilities, largely in support of energy infrastructure investment, and the impact of foreign exchange on the translation of US dollar-denominated debt. The increase was partially offset by regularly scheduled debt repayments and net repayments under committed credit facilities, mainly at the Corporation, using net proceeds from the sale of commercial real estate and hotel assets. |
| Capital lease and finance obligations (including current portion) | (190) | The decrease was mainly due to the purchase of an additional ownership interest in the Springerville Unit 1 generating facility and the Springerville coal handling facilities at UNS Energy following the expiry of lease arrangements. |
| Deferred income tax liabilities | 424 | The increase was primarily due to tax timing differences mainly related to capital expenditures at the regulated utilities and the impact of foreign exchange on the translation of US dollar-denominated deferred income tax liabilities. |
| Shareholders' equity (before non-controlling interests) |
1,189 | The increase primarily related to: (i) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; (ii) net earnings attributable to common equity shareholders for 2015, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans. |
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY OF CONSOLIDATED CASH FLOWS
The table below outlines the Corporation's sources and uses of cash in 2015 compared to 2014, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows | |||||||
| Years Ended December 31 | |||||||
| ($ millions) | 2015 | 2014 | Variance | ||||
| Cash, Beginning of Year | 230 | 72 | 158 | ||||
| Cash Provided by (Used in): | |||||||
| Operating Activities | 1,673 | 982 | 691 | ||||
| Investing Activities | (1,368 | ) | (4,199 | ) | 2,831 | ||
| Financing Activities | (346 | ) | 3,361 | (3,707 | ) | ||
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | 53 | 14 | 39 | ||||
| Cash, End of Year | 242 | 230 | 12 | ||||
Operating Activities: Cash flow from operating activities in 2015 was $691 million higher than in 2014. The increase was driven by higher cash earnings and favourable changes in working capital. The increase in cash earnings was driven by the acquisition of UNS Energy in August 2014. Earnings contribution from the Waneta Expansion and higher cash earnings at FortisAlberta also contributed to the increase. Favourable changes in working capital at FortisBC Energy and UNS Energy were partially offset by unfavourable changes at FortisAlberta.
A graph is available at the following address: http://media3.marketwire.com/docs/cff1.pdf
Investing Activities: Cash used in investing activities in 2015 was $2,831 million lower than in 2014. The decrease was due to the acquisition of UNS Energy in August 2014 for a net cash purchase price of $2,745 million. Also contributing to the decrease were proceeds received from the sale of commercial real estate assets in June 2015 for $430 million, hotel assets in October 2015 for $365 million, and generation assets in Upstate New York in June 2015 for $77 million (US$63 million), compared to proceeds of $105 million (US$95 million) on the sale of Griffith in March 2014. The decrease was partially offset by an increase in capital expenditures of $518 million, driven by a full year contribution from UNS Energy and higher capital spending at most of the Corporation's regulated utilities, partially offset by lower non-regulated capital expenditures due to the completion of the Waneta Expansion and the sale of commercial real estate and hotel assets.
Financing Activities: Cash provided by financing activities in 2015 was $3,707 million lower than in 2014. The decrease was primarily due to financing associated with the acquisition of UNS Energy in August 2014 and the repayment of credit facility borrowings in 2015 using proceeds from the sale of commercial real estate and hotel assets. The acquisition of UNS Energy was financed from proceeds of $1,800 million, or $1,725 million net of issue costs, from the issue of convertible debentures, proceeds from the issuance of preference shares and credit facility borrowings. In October 2014 substantially all of the convertible debentures were converted into 58.2 million common shares of Fortis.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for 2015 and 2014 are summarized in the following tables.
| Proceeds from Long-Term Debt, Net of Issue Costs | ||||
| Years Ended December 31 | ||||
| ($ millions) | 2015 | 2014 | Variance | |
| UNS Energy (1) | 591 | - | 591 | |
| Central Hudson (2) | 25 | 33 | (8 | ) |
| FortisBC Energy (3) | 150 | - | 150 | |
| FortisAlberta (4) | 149 | 274 | (125 | ) |
| FortisBC Electric (5) | - | 198 | (198 | ) |
| Newfoundland Power (6) | 75 | - | 75 | |
| Caribbean Utilities (7) | - | 57 | (57 | ) |
| Fortis Turks and Caicos (8) | 12 | 92 | (80 | ) |
| Corporate (9) | - | 539 | (539 | ) |
| Total | 1,002 | 1,193 | (191 | ) |
| (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 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. In March 2014 Central Hudson issued 10-year US$30 million unsecured notes with a floating interest rate of 3-month LIBOR plus 1%. The net proceeds were used to repay maturing long-term debt and for other general corporate purposes. |
| (3) | 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 2015 FortisAlberta issued 30-year $150 million 4.27% senior unsecured debentures. The net proceeds were used to repay credit facility borrowings and for general corporate purposes. In September 2014 FortisAlberta issued $275 million senior unsecured debentures in a dual tranche of 10-year $150 million at 3.30% and 30-year $125 million at 4.11%. The net proceeds were used to repay maturing long-term debt, finance capital expenditures and for general corporate purposes. |
| (5) | In October 2014 FortisBC Electric issued 30-year $200 million 4.00% senior unsecured debentures. The net proceeds were used to repay long-term debt and credit facility borrowings. |
| (6) | 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. |
| (7) | In November 2014 Caribbean Utilities issued a total of US$50 million unsecured notes with terms to maturity ranging from 15 to 32 years and coupon rates ranging from 3.65% to 4.53%. The net proceeds were used to finance capital expenditures. |
| (8) | 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. In December 2014 Fortis Turks and Caicos issued 15-year US$80 million 4.75% unsecured notes. The net proceeds were used to repay inter-company loans with a direct subsidiary of Fortis. |
| (9) | In June 2014 the Corporation issued US$213 million unsecured notes with terms to maturity ranging from 5 to 30 years and coupon rates ranging from 2.92% to 4.88%. The weighted average term to maturity was approximately 9 years and the weighted average coupon rate was 3.51%. Net proceeds were used to repay US-dollar denominated borrowings on the Corporation's committed credit facility and for general corporate purposes. In September 2014 the Corporation issued US$287 million unsecured notes with terms to maturity ranging from 7 to 30 years and coupon rates ranging from 3.64% to 5.03%. The weighted average term to maturity was approximately 12 years and the weighted average coupon rate was 4.11%. Net proceeds were used to repay long-term debt and for general corporate purposes. |
| Repayments of Long-Term Debt and Capital Lease and Finance Obligations | ||||||
| Years Ended December 31 | ||||||
| ($ millions) | 2015 | 2014 | Variance | |||
| UNS Energy | (449 | ) | - | (449 | ) | |
| Central Hudson | - | (24 | ) | 24 | ||
| FortisBC Energy | (92 | ) | (6 | ) | (86 | ) |
| FortisAlberta | - | (200 | ) | 200 | ||
| FortisBC Electric | - | (140 | ) | 140 | ||
| Newfoundland Power | (6 | ) | (35 | ) | 29 | |
| Caribbean Utilities | (17 | ) | (19 | ) | 2 | |
| Fortis Turks and Caicos | (4 | ) | (4 | ) | - | |
| Fortis Properties | (34 | ) | (22 | ) | (12 | ) |
| Corporate | - | (293 | ) | 293 | ||
| Total | (602 | ) | (743 | ) | 141 | |
| Net (Repayments) Borrowings Under Committed Credit Facilities | ||||||
| Years Ended December 31 | ||||||
| ($ millions) | 2015 | 2014 | Variance | |||
| UNS Energy | (199 | ) | 61 | (260 | ) | |
| FortisAlberta | 30 | 3 | 27 | |||
| FortisBC Electric | - | (54 | ) | 54 | ||
| Newfoundland Power | (47 | ) | 65 | (112 | ) | |
| Corporate | (406 | ) | 535 | (941 | ) | |
| Total | (622 | ) | 610 | (1,232 | ) | |
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility.
In September 2014 Fortis issued 24 million First Preference Shares, Series M for gross proceeds of $600 million. The net proceeds were used to repay a portion of credit facility borrowings used to initially finance a portion of the acquisition of UNS Energy.
Common share dividends paid in 2015 totalled $232 million, net of $156 million of dividends reinvested, compared to $194 million, net of $81 million of dividends reinvested, paid in 2014. The increase in dividends paid was due to a higher annual dividend paid per common share and an increase in the number of common shares outstanding. The dividend paid per common share was $1.40 in 2015 compared to $1.28 in 2014. The weighted average number of common shares outstanding was 278.6 million for 2015 compared to 225.6 million for 2014.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at December 31, 2015, are outlined in the following table.
| Contractual Obligations As at December 31, 2015 ($ millions) |
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 |
| Long-term debt | 11,240 | 384 | 71 | 283 | 239 | 857 | 9,406 |
| Interest obligations on long-term debt | 9,435 | 536 | 512 | 507 | 495 | 488 | 6,897 |
| Capital lease and finance obligations (1) | 2,478 | 72 | 74 | 93 | 77 | 75 | 2,087 |
| Renewable power purchase obligations (2) | 1,589 | 93 | 93 | 92 | 92 | 92 | 1,127 |
| Gas purchase obligations (3) | 1,449 | 366 | 253 | 222 | 153 | 131 | 324 |
| Power purchase obligations (4) | 1,440 | 281 | 209 | 180 | 102 | 36 | 632 |
| Long-term contracts - UNS Energy (5) | 1,057 | 146 | 141 | 105 | 102 | 82 | 481 |
| Capital cost (6) | 488 | 19 | 19 | 19 | 19 | 19 | 393 |
| Operating lease obligations (7) | 181 | 12 | 11 | 11 | 11 | 8 | 128 |
| Renewable energy credit purchase agreements (8) | 162 | 13 | 13 | 13 | 13 | 13 | 97 |
| Purchase of Springerville Common Facilities (9) | 147 | - | 53 | - | - | - | 94 |
| Employee future benefits funding contributions | 139 | 49 | 12 | 8 | 9 | 9 | 52 |
| Waneta Partnership promissory note | 72 | - | - | - | - | 72 | - |
| Joint-use asset and shared service agreements | 53 | 3 | 3 | 3 | 3 | 3 | 38 |
| Other (10) | 71 | 15 | 12 | 16 | 3 | - | 25 |
| Total | 30,001 | 1,989 | 1,476 | 1,552 | 1,318 | 1,885 | 21,781 |
| (1) | Includes principal payments, imputed interest and executory costs, mainly related to FortisBC Electric's capital lease obligations. |
| (2) | TEP and UNS Electric are party to 20-year long-term renewable PPAs totalling approximately US$1,148 million as at December 31, 2015, which require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities that have achieved commercial operation. While TEP and UNS Electric are not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. These agreements have various expiry dates through 2035. TEP has entered into additional long-term renewable PPAs to comply with renewable energy standards of the State of Arizona; however, the Company's obligation to purchase power under these agreements does not begin until the facilities are operational. In February 2016 one of the generating facilities achieved commercial operation, increasing estimated future payments of renewable PPAs by US$58 million, which is not included in the table above. |
| (3) | Certain of the Corporation's subsidiaries, mainly FortisBC Energy and Central Hudson, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2015. At Central Hudson, the obligations are based on tariff rates, negotiated rates and market prices as at December 31, 2015. |
| (4) | Power purchase obligations include various power purchase contracts held by certain of the Corporation's subsidiaries, as described below. |
| FortisBC Energy | |
| In March 2015 FortisBC Energy entered into an Electricity Supply Agreement with BC Hydro for the purchase of electricity supply to the Tilbury Expansion Project, with purchase obligations totalling $513 million as at December 31, 2015. | |
| FortisBC Electric | |
| Power purchase obligations for FortisBC Electric, totalling $292 million as at December 31, 2015, mainly include a PPA with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term, as approved by the BCUC. The capacity and energy to be purchased under this agreement do not relate to a specific plant. | |
| In addition, in November 2011 FortisBC Electric executed the Waneta Expansion Capacity Agreement ("WECA"), allowing FortisBC Electric to purchase 234 MW of capacity for 40 years, effective April 2015, as approved by the BCUC. Amounts associated with the WECA have not been included in the Contractual Obligations table as they are to be paid by FortisBC Electric to a related party and such a related-party transaction would be eliminated upon consolidation with Fortis. | |
| FortisOntario | |
| Power purchase obligations for FortisOntario, totalling $208 million as at December 31, 2015, primarily include two long-term take-or-pay contracts between Cornwall Electric and Hydro-Quebec Energy Marketing for the supply of electricity and capacity, both expiring in December 2019. The first contract provides approximately 237 GWh of energy per year and up to 45 MW of capacity at any one time. The second contract provides 100 MW of capacity and provides a minimum of 300 GWh of electricity per contract year. | |
| Maritime Electric | |
| Power purchase obligations for Maritime Electric, totalling $194 million as at December 31, 2015, primarily include two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2019 and November 2032, as well as an Energy Purchase Agreement with New Brunswick Power ("NB Power") expiring in February 2019. | |
| Central Hudson | |
| Central Hudson's power purchase obligations totalled US$124 million as at December 31, 2015. In June 2014 Central Hudson entered into a contract to purchase available installed capacity from the Danskammer Generating Facility from October 2014 through August 2018 with approximately US$76 million in purchase commitments remaining as at December 31, 2015. During 2015, Central Hudson entered into agreements to purchase electricity on a unit-contingent basis at defined prices during peak load periods from June 2015 through August 2016, replacing existing contracts which expired in March 2015. | |
| (5) | UNS Energy has entered into various long-term contracts for the purchase and delivery of coal to fuel its generating facilities, the purchase of gas transportation services to meet its load requirements, and the purchase of transmission services for purchased power, with obligations totalling US$440 million, US$261 million and US$63 million, respectively, as at December 31, 2015. Amounts paid under contracts for the purchase and delivery of coal depend on actual quantities purchased and delivered. Certain of these contracts also have price adjustment clauses that will affect future costs under the contracts. As a result of the restructuring of the ownership of the San Juan generating station in January 2016, a new coal supply agreement came into effect under which TEP's minimum purchase obligations are US$137 million, which is not included in the previous table. |
| (6) | Maritime Electric has entitlement to approximately 4.55% of the output from NB Power's Point Lepreau nuclear generating station for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit. |
| (7) | Operating lease obligations include certain office, warehouse, natural gas T&D asset, rail car, land easement and rights-of-way, and vehicle and equipment leases. |
| (8) | UNS Energy is party to renewable energy credit purchase agreements, totalling approximately US$117 million as at December 31, 2015, to purchase the environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are paid in contractually agreed-upon intervals based on metered renewable energy production. |
| (9) | UNS Energy has entered into a commitment to exercise its fixed-price purchase provision to purchase an undivided 50% leased interest in the Springerville Common Facilities if the lease is not renewed, for a purchase price of US$106 million, with one facility to be acquired in 2017 and the remaining two facilities to be acquired in 2021. |
| (10) | Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including Performance Share Unit, Restricted Share Unit and Directors' Deferred Share Unit Plan obligations and asset retirement obligations. |
Other Contractual Obligations
Capital Expenditures: The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. The regulated utilities' capital expenditures are largely driven by the need to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. The Corporation's consolidated capital expenditure program, including capital spending at its non-regulated operations, is forecast to be approximately $1.9 billion for 2016. Over the five years 2016 through 2020, the Corporation's consolidated capital expenditure program is expected to be approximately $9 billion, which has not been included in the Contractual Obligations table.
Other: CH Energy Group is party to an investment to develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with the U.S. Federal Energy Regulatory Commission ("FERC") for the recovery of the cost of and return on five high-voltage transmission projects totalling US$1.7 billion, of which CH Energy Group's maximum commitment is US$182 million. CH Energy Group issued a parental guarantee to assure the payment of maximum commitment of US$182 million. As at December 31, 2015, no payment obligation is expected under this guarantee.
FortisBC Energy issued commitment letters to customers, totalling $33 million as at December 31, 2015, to provide Energy Efficiency and Conservation ("EEC") funding under the EEC program approved by the BCUC.
Caribbean Utilities is party to primary and secondary fuel supply contracts and is committed to purchasing approximately 60% and 40%, respectively, of the Company's diesel fuel requirements under the contracts for the operation of its diesel-powered generating plant. The approximate combined quantity under the contracts for 2016 is 20 million imperial gallons. Fortis Turks and Caicos has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 12 million imperial gallons per annum.
The Corporation's long-term regulatory liabilities of $1,340 million as at December 31, 2015 have been excluded from the Contractual Obligations table, as the final timing of settlement of many of the liabilities is subject to further regulatory determination or the settlement periods are not currently known. The nature and amount of the long-term regulatory liabilities are detailed in Note 8 to the Corporation's 2015 Audited Consolidated Financial Statements.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 35% common equity, 65% debt and preferred equity, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure | ||||
| As at December 31 | 2015 | 2014 | ||
| ($ millions) | (%) | ($ millions) | (%) | |
| Total debt and capital lease and finance obligations (net of cash) (1) | 11,950 | 54.8 | 11,239 | 56.4 |
| Preference shares | 1,820 | 8.3 | 1,820 | 9.1 |
| Common shareholders' equity | 8,060 | 36.9 | 6,871 | 34.5 |
| Total (2) | 21,830 | 100.0 | 19,930 | 100.0 |
| (1) | Includes long-term debt and capital lease and finance obligations, including current portions, and short-term borrowings, net of cash |
| (2) | Excludes amounts related to non-controlling interests |
Excluding capital lease and finance obligations, the Corporation's capital structure as at December 31, 2015 was 53.7% debt, 8.5% preference shares and 37.8% common shareholders' equity (December 31, 2014 - 54.8% debt, 9.5% preference shares and 35.7% common shareholders' equity).
The improvement in the Corporation's capital structure was due to an increase in common shareholders' equity as a result of: (i) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; (ii) net earnings attributable to common equity shareholders for the year ended December 31, 2015, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans. The capital structure was also impacted by an increase in total debt due to the impact of foreign exchange on the translation of US-dollar denominated debt and new debt in support of energy infrastructure investment, partially offset by regular scheduled debt repayments and net repayments under committed credit facilities.
CREDIT RATINGS
As at December 31, 2015, the Corporation's credit ratings were as follows:
| Standard & Poor's ("S&P") | A- / Stable (long-term corporate and unsecured debt credit rating) |
| DBRS | A (low) / Stable (unsecured debt credit rating) |
The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and management's commitment to maintaining reasonable levels of debt at the holding company level. In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC, S&P affirmed the Corporation's long-term corporate credit rating at A-, revised its unsecured debt credit rating to BBB+ from A-, and revised its outlook on the Corporation to negative from stable. Similarly, in February 2016 DBRS placed the Corporation's credit rating under review with negative implications.
CAPITAL EXPENDITURE PROGRAM
Capital investment in energy infrastructure is required to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems, and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred. Approximately $276 million in maintenance and repairs was expensed in 2015 compared to approximately $203 million in 2014. The increase was largely due to a full year of expense for UNS Energy in 2015.
Gross consolidated capital expenditures for 2015 were approximately $2.2 billion. A breakdown of these capital expenditures by segment and asset category for 2015 is provided in the following table.
| Gross Consolidated Capital Expenditures (1) | |||||||||||
| Year Ended December 31, 2015 | |||||||||||
| ($ millions) | |||||||||||
| Regulated Utilities | Non-Regulated | ||||||||||
| |
UNS Energy |
Central Hudson |
FortisBC Energy |
Fortis Alberta |
FortisBC Electric |
Eastern Canadian |
Caribbean Electric |
Total Regulated Utilities |
Fortis Generation |
Non- Utility(2) |
Total |
| Generation | 321 | 1 | - | - | 3 | 9 | 107 | 441 | 38 | - | 479 |
| Transmission | 131 | 37 | 57 | - | 19 | 23 | 2 | 269 | - | - | 269 |
| Distribution | 135 | 102 | 134 | 358 | 38 | 121 | 16 | 904 | - | - | 904 |
| Facilities, equipment, vehicles and other (3) | 39 | 27 | 254 | 73 | 35 | 14 | 9 | 451 | - | 28 | 479 |
| Information technology | 43 | 14 | 15 | 21 | 8 | 8 | 3 | 112 | - | - | 112 |
| Total | 669 | 181 | 460 | 452 | 103 | 175 | 137 | 2,177 | 38 | 28 | 2,243 |
| (1) | Represents cash payments to construct utility capital assets, non-utility capital assets and intangible assets, as reflected on the consolidated statement of cash flows. Excludes the non-cash equity component of AFUDC. |
| (2) | Includes capital expenditures of approximately $14 million at FAES, which is reported in the Corporate and Other segment |
| (3) | Includes capital expenditures associated with the Tilbury Expansion at FortisBC Energy and Alberta Electric System Operator ("AESO") transmission-related capital expenditures at FortisAlberta |
Planned capital expenditures are based on detailed forecasts of energy demand, cost of labour and materials, as well as other factors, including economic conditions and foreign exchange rates, which could change and cause actual expenditures to differ from those forecast. Gross consolidated capital expenditures of $2,243 million for 2015 were $91 million higher than $2,152 million forecast for 2015, as disclosed in the MD&A for the year ended December 31, 2014. The increase was driven by higher capital spending at FortisBC Energy primarily due to the timing of payments associated with the Tilbury Expansion and at FortisAlberta primarily due to the purchase of two Rural Electrification Associations ("REAs") for approximately $21 million in 2015, and due to the impact of foreign exchange associated with the translation of US dollar-denominated capital expenditures. The increase was partially offset by lower-than-forecast capital spending at the Waneta Expansion, due to the timing of payments, and at FAES.
Gross consolidated capital expenditures for 2016 are expected to be approximately $1.9 billion. A breakdown of forecast gross consolidated capital expenditures by segment and asset category for 2016 is provided in the following table.
| Forecast Gross Consolidated Capital Expenditures (1) | |||||||||||
| Year Ending December 31, 2016 | |||||||||||
| ($ millions) | |||||||||||
| Regulated Utilities | Non-Regulated | ||||||||||
UNS Energy |
Central Hudson |
FortisBC Energy |
Fortis Alberta |
FortisBC Electric |
Eastern Canadian |
Caribbean Electric |
Total Regulated Utilities |
Fortis Generation |
Non- Utility (2) |
Total |
|
| Generation | 162 | 2 | - | - | 2 | 24 | 73 | 263 | 15 | - | 278 |
| Transmission | 66 | 30 | 84 | - | 21 | 19 | 6 | 226 | - | - | 226 |
| Distribution | 168 | 142 | 129 | 311 | 29 | 110 | 23 | 912 | - | - | 912 |
| Facilities, equipment, | |||||||||||
| vehicles and other (3) | 40 | 25 | 118 | 109 | 16 | 9 | 20 | 337 | - | 3 | 340 |
| Information technology | 49 | 29 | 18 | 21 | 11 | 12 | 5 | 145 | - | - | 145 |
| Total | 485 | 228 | 349 | 441 | 79 | 174 | 127 | 1,883 | 15 | 3 | 1,901 |
| (1) | Represents forecast cash payments to construct utility capital assets and intangible assets, as would be reflected on the consolidated statement of cash flows. Excludes the non-cash equity component of AFUDC. Forecast capital expenditures for 2016 are based on a forecast exchange rate of US$1.00=CAD$1.38. |
| (2) | Includes forecast capital expenditures of approximately $3 million at FAES, which is reported in the Corporate and Other segment |
| (3) | Includes forecast capital expenditures associated with the Tilbury Expansion at FortisBC Energy and AESO transmission-related capital expenditures at FortisAlberta |
The percentage breakdown of 2015 actual and 2016 forecast gross consolidated capital expenditures among growth, sustaining and other is as follows.
| Gross Consolidated Capital Expenditures | ||
| Year Ending December 31 | Actual | Forecast |
| (%) | 2015 | 2016 |
| Growth (1) | 40 | 36 |
| Sustaining (2) | 44 | 48 |
| Other (3) | 16 | 16 |
| Total | 100 | 100 |
| (1) | Includes capital expenditures associated with the Tilbury Expansion at FortisBC Energy and AESO transmission-related capital expenditures at FortisAlberta |
| (2) | Capital expenditures required to ensure continued and enhanced performance, reliability and safety of generation and T&D assets |
| (3) | Relates to facilities, equipment, vehicles, information technology systems and other assets |
Over the five-year period 2016 through 2020, excluding the pending acquisition of ITC, gross consolidated capital expenditures are expected to be approximately $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 40% at Regulated Electric & Gas Utilities in the United States; 37% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 17% at Canadian Regulated Gas Utility; 5% at Caribbean Regulated Electric Utilities; and the remaining 1% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 35% to meet customer growth; 50% to ensure continued and enhanced performance, reliability and safety of generation and T&D assets, i.e., sustaining capital expenditures; and 15% for facilities, equipment, vehicles, information technology and other assets.
Actual 2015 and forecast 2016 midyear rate base for the Corporation's regulated utilities and the Waneta Expansion is provided in the following table.
| Midyear Rate Base | Actual | Forecast |
| ($ billions) | 2015 | 2016 |
| UNS Energy (1) | 4.1 | 4.8 |
| Central Hudson (1) | 1.4 | 1.6 |
| FortisBC Energy | 3.7 | 3.7 |
| FortisAlberta | 2.7 | 3.0 |
| FortisBC Electric | 1.3 | 1.3 |
| Eastern Canadian Electric Utilities | 1.6 | 1.7 |
| Regulated Electric Utilities - Caribbean (1) | 0.8 | 0.9 |
| Waneta Expansion | 0.8 | 0.8 |
| Total | 16.4 | 17.8 |
| (1) | Actual midyear rate base for 2015 is based on the actual average exchange rate of US$1.00=CAD$1.28 and forecast midyear rate base for 2016 is based on a forecast exchange rate of US$1.00=CAD$1.38. |
The most significant capital projects that are included in the Corporation's base consolidated capital expenditures for 2015 and 2016 are summarized in the table below.
| Significant Capital Projects (1) | Forecast | Expected | ||||
| ($ millions) | Pre- | Actual | Forecast | 2017- | Year of | |
| Company | Nature of Project | 2015 | 2015 | 2016 | 2020 | Completion |
| UNS Energy (2) | Interest in Springerville Unit 1 | 23 | 57 | - | - | 2015 |
| Springerville Coal Handling | ||||||
| Facilities Lease Buyout | - | 91 | - | - | 2015 | |
| Pinal Transmission Project | 9 | 84 | - | - | 2015 | |
| Residential Solar Program | - | 1 | 22 | 90 | Ongoing | |
| Central Hudson (2) | Gas Main Replacement Program | 7 | 19 | 29 | 135 | Post-2020 |
| FortisBC Energy | Tilbury LNG Facility | |||||
| Expansion (3) | 145 | 181 | 105 | 15 | 2016 | |
| Lower Mainland System Upgrade | 4 | 11 | 50 | 362 | 2018 | |
| FortisAlberta | Pole-Management Program | 159 | 41 | 42 | 94 | Post-2020 |
| Caribbean Utilities (2) | Generation Expansion | 12 | 61 | 35 | - | 2016 |
| Waneta Partnership | Waneta Expansion (4) | 679 | 36 | 13 | 97 | 2015 |
| (1) | Represents utility capital asset and intangible asset expenditures, including both the capitalized interest and equity components of AFUDC, where applicable |
| (2) | Forecast capital expenditures are based on a forecast exchange rate of US$1.00=CAD$1.38 for 2016 through 2020 |
| (3) | Total project investment as at December 31, 2014 and 2015 includes approximately $43 million and $11 million, respectively, in non-cash capital accruals |
| (4) | Includes the $72 million payment expected to be made in 2020 and excludes forecast capitalized interest of the minority partners, CPC/CBT, in the Waneta Partnership |
UNS Energy completed three significant capital investments in 2015. In January 2015, upon expiration of the Springerville Unit 1 lease, UNS Energy purchased an additional ownership interest in Springerville Unit 1 for US$46 million. This purchase increased the ownership interest to 49.5%. Additionally, upon expiration of the Springerville Coal Handling Facilities lease in April 2015, UNS Energy purchased an ownership interest in the coal-handling assets for US$72 million. The Pinal Transmission Project at UNS Energy was also completed in 2015 at a total project cost of US$79 million. The project consisted of the construction of a 500-kilovolt transmission line in Pinal County that will increase the Company's import capacity from Gila River Unit 3 and the Palo Verde trading hub.
The Residential Solar Program at UNS Energy is a partnership with local solar companies for UNS Energy to own and install rooftop solar systems for residential customers. The total capital cost of the program through 2020 is expected to be approximately US$82 million, with approximately US$16 million expected to be spent in 2016.
The Gas Main Replacement Program at Central Hudson is a 15-year replacement program to eliminate and replace leakage-prone pipes throughout the gas distribution system. The proposed replacement program increases the rate of annual expenditures on pipe replacements to approximately US$20 million to expedite the replacement plan. Approximately US$15 million was spent on this program in 2015 and an additional US$21 million is expected to be spent in 2016. The majority of spending is expected post 2020.
FortisBC Energy's ongoing Tilbury LNG Facility Expansion, at an estimated total project cost of $440 million, will include a second LNG tank and a new liquefier, both to be in service around the end of 2016. FortisBC Energy received an Order in Council from the Government of British Columbia exempting the Tilbury LNG Facility project from further regulatory review. Key construction activities in 2015 were focused on construction of the storage tank and liquefaction process areas. Total projects costs to the end of 2015 were approximately $326 million.
The Lower Mainland System Upgrade project at FortisBC Energy is in place to address system capacity and pipeline condition issues for the gas supply system in the Lower Mainland area of British Columbia. The project will be completed in two phases: (i) the Lower Mainland Intermediate Pressure System Upgrade project phase, which is focused on addressing pipeline condition issues; and (ii) the Coastal Transmission System phase, which is intended to increase security of supply by reducing the number of single points of failure. The project has an estimated capital cost of $427 million, with approximately $50 million forecast to be spent in 2016, and is expected to be completed in 2018. The BCUC approved the application to replace certain sections of intermediate pressure pipeline segments within the Greater Vancouver area in October 2015. The Coastal Transmission System phase was approved by a Special Direction by the Government of British Columbia in 2014 and will not be subject to further regulatory review.
During 2015 FortisAlberta continued with the replacement of vintage poles under its Pole-Management Program to extend the service life of existing poles and to replace poles when deterioration is beyond repair. The total capital cost of the program through 2020 is expected to be approximately $336 million. Approximately $41 million was spent on this program in 2015, for a total of $200 million spent to date.
Caribbean Utilities was the successful bidder for new generation capacity and entered into a design-build contract agreement to cover the purchase and turnkey installation of two 18.5 MW diesel-generating units, one 2.7 MW waste heat recovery steam turbine and associated auxiliary equipment. Approximately US$48 million was spent on the project in 2015, with approximately US$25 million forecast to be spent in 2016. The project cost is estimated to be US$85 million and the plant is expected to be commissioned in mid-2016.
Construction of the $900 million, 335-MW Waneta Expansion was completed on April 1, 2015, ahead of schedule and on budget. Construction of the Waneta Expansion, which is adjacent to the Waneta Dam and powerhouse facilities on the Pend d'Oreille River, south of Trail, British Columbia, commenced late in 2010. The expansion added a second powerhouse, immediately downstream of the Waneta Dam on the Pend d'Oreille River, that shares the existing hydraulic head and generates clean, renewable, cost-effective power from water that would otherwise be spilled. The project also included construction of a 10-kilometre, 230-kilovolt transmission line. On April 2, 2015, the Waneta Expansion began generating power, all of which is being sold to BC Hydro and FortisBC Electric under 40-year contracts. Fortis owns a 51% interest in the Waneta Partnership and operates and maintains the non-regulated investment. The capital cost of the Waneta Expansion, as reported in the Significant Capital Projects table, includes capitalized interest by Fortis during construction, as well as other eligible capitalized expenses, and a $72 million payment expected to be made in 2020 related to accrued development costs previously incurred by CPC/CBT. The table excludes approximately $50 million of forecast capitalized interest of the minority partners in the Waneta Partnership.
ADDITIONAL INVESTMENT OPPORTUNITIES
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's base capital expenditure forecast and also exclude the acquisition of ITC.
FortisBC Energy is pursuing additional LNG infrastructure investment opportunities, including a pipeline expansion to the proposed Woodfibre LNG site in 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 BCUC.
The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. The Woodfibre LNG plant has passed the British Columbia Environmental Assessment Office review and the Squamish First Nation approved an environmental certificate for the project in October 2015. These approvals are significant milestones; however, the project is pending a Federal Environmental Assessment. In addition, FortisBC Energy's pipeline expansion, at an estimated total project cost of up to $600 million, is also subject to various environmental approvals. A final investment decision by Woodfibre LNG is expected in 2016.
A further expansion of Tilbury is conditional upon having long-term contracts in place for the offtake of 70% of the additional liquefaction capacity, on average, for the first 15 years of operation. FortisBC Energy has a conditional agreement with Hawaiian Electric Company that would meet this requirement, subject to the regulatory approval process in Hawaii. The Corporation continues to have discussions with Hawaiian Electric Company, which is expected to be the primary offtaker, regarding the viability and scope of the project. Any resulting agreement would be subject to the approval of the Hawaii Public Utilities Commission.
The Corporation also has other significant opportunities that have not yet been included in the Corporation's capital expenditure forecast including, but not limited to, the New York Transco, LLC at Central Hudson to address transmission constraints in New York; renewable energy alternatives at UNS Energy; Wataynikaneyap transmission line to connect remote First Nations communities at FortisOntario; further gas infrastructure opportunities at FortisBC Energy; and 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. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis.
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. For a discussion of the Corporation's cash flow requirements associated with the pending acquisition of ITC, refer to the "Business Risk Management - Risks Associated with the Acquisition of ITC" and "Subsequent Event" sections 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 2015 FortisBC Energy issued 30-year $150 million 3.38% unsecured debentures under the base shelf prospectus.
In June 2015 Fortis injected US$180 million of equity into TEP. Proceeds were used to repay credit facility borrowings in June 2015 and the balance was used to redeem bonds in August 2015 and provide additional liquidity to TEP. This equity injection fulfilled one of the commitments made by Fortis in order to receive regulatory approval for the acquisition of UNS Energy, and increased TEP's common equity component of capital structure to almost 50%, which is comparable with other regulated utilities in Arizona.
In May 2015 Caribbean Utilities completed a rights offering in which it raised gross proceeds of US$32 million through the issue of 2.9 million common shares. Fortis invested US$23 million in approximately 2.2 million common shares of Caribbean Utilities. The net proceeds from the rights offering were used by Caribbean Utilities 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.
As at December 31, 2015, management expects consolidated fixed-term debt maturities and repayments to be $313 million in 2016 and to average approximately $260 million annually over the next five years. The combination of available credit facilities and relatively low annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets. For a discussion of capital resources and liquidity risk, refer to the "Business Risk Management - Capital Resources and Liquidity Risk" section of this MD&A.
Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2015 and are expected to remain compliant in 2016.
CREDIT FACILITIES
As at December 31, 2015, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.6 billion, of which approximately $2.4 billion was unused, including $570 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, as well as large banks in the United States, with no one bank holding more than 20% of these facilities. Approximately $3.3 billion of the total credit facilities are committed facilities with maturities ranging from 2016 through 2020.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities | Total as at | Total as at | |||||||
| Regulated | Corporate | December 31, | December 31, | ||||||
| ($ millions) | Utilities | and Other | 2015 | 2014 | |||||
| Total credit facilities (1) | 2,211 | 1,354 | 3,565 | 3,854 | |||||
| Credit facilities utilized: | |||||||||
| Short-term borrowings | (511 | ) | - | (511 | ) | (330 | ) | ||
| Long-term debt (including current portion) (2) | (71 | ) | (480 | ) | (551 | ) | (1,096 | ) | |
| Letters of credit outstanding | (68 | ) | (36 | ) | (104 | ) | (192 | ) | |
| Credit facilities unused | 1,561 | 838 | 2,399 | 2,236 | |||||
| (1) | Total credit facilities exclude a $300 million option to increase the Corporation's committed corporate credit facility, as discussed below. |
| (2) | As at December 31, 2015, credit facility borrowings classified as long-term debt included $71 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2014 - $257 million). |
As at December 31, 2015 and 2014, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods.
Regulated Utilities
The UNS Utilities have a total of US$350 million ($484 million) in unsecured committed revolving credit facilities maturing in October 2020, with the option of two one-year extensions.
Central Hudson has a US$200 million ($277 million) unsecured committed revolving credit facility, maturing in October 2020, that is utilized to finance capital expenditures and for general corporate purposes. Central Hudson also has an uncommitted credit facility totalling US$25 million ($34 million).
FEI has a $700 million unsecured committed revolving credit facility, maturing in August 2018, that is utilized to finance working capital requirements, capital expenditures and for general corporate purposes.
FortisAlberta has a $250 million unsecured committed revolving credit facility, maturing in August 2020, that is utilized to finance capital expenditures and for general corporate purposes.
FortisBC Electric has a $150 million unsecured committed revolving credit facility, maturing in May 2018. This facility is utilized to finance capital expenditures and for general corporate purposes. FortisBC Electric also has a $10 million unsecured demand overdraft facility.
Newfoundland Power has a $100 million unsecured committed revolving credit facility, maturing in August 2019, and a $20 million demand credit facility. Maritime Electric has a $50 million unsecured committed revolving credit facility, maturing in February 2019, and a $5 million unsecured demand credit facility. FortisOntario has a $30 million unsecured committed revolving credit facility, maturing in June 2016.
Caribbean Utilities has unsecured credit facilities totalling approximately US$47 million ($65 million). Fortis Turks and Caicos has short-term unsecured demand credit facilities of US$26 million ($36 million), maturing in September 2016.
Corporate and Other
Fortis has a $1 billion unsecured committed revolving credit facility, maturing in July 2020, that is available for general corporate purposes. The Corporation has the ability to increase this facility to $1.3 billion. As at December 31, 2015, the Corporation has not yet exercised its option for the additional $300 million. The Corporation also has a $35 million letter of credit facility, maturing in January 2017.
UNS Energy Corporation has a US$150 million ($208 million) unsecured committed revolving credit facility, maturing in October 2020, with the option of two one-year extensions.
CH Energy Group has a US$50 million ($69 million) unsecured committed revolving credit facility, maturing in July 2020, that can be utilized for general corporate purposes.
FHI has a $30 million unsecured committed revolving credit facility, maturing in April 2018, that is available for general corporate purposes.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $104 million as at December 31, 2015 (December 31, 2014 - $192 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
The following is a summary of the Corporation's significant business risks.
Regulatory Risk: The Corporation's key business risk is regulation. Regulated utility assets comprised approximately 96% of total assets of Fortis as at December 31, 2015 (December 31, 2014 - 93%). Approximately 96% of the Corporation's operating revenue1 was derived from regulated utility operations in 2015 (2014 - 95%), and approximately 92% of the Corporation's operating earnings1, excluding the gains on sale of non-core assets, were derived from regulated utility operations in 2015 (2014 - 91%). The Corporation operates nine utilities in different jurisdictions in Canada, the United States and the Caribbean, with no more than one-third of total assets located in any one regulatory jurisdiction.
| (1) | Operating revenue and operating earnings are non-US GAAP measures and refer to total revenue, excluding Corporate and Other segment revenue and inter-segment eliminations, and net earnings attributable to common equity shareholders, excluding Corporate and Other segment expenses, respectively. Operating revenue and operating earnings are referred to by users of the consolidated financial statements in evaluating the performance of the Corporation's operating subsidiaries. |
Each of the Corporation's regulated utilities is subject to normal regulation that can affect future revenue and earnings. As a result, the utilities are subject to uncertainties faced by regulated entities, including approval by the respective regulatory authorities of electricity and gas rates that permit a reasonable opportunity to recover, on a timely basis, the estimated COS, including a fair rate of return on rate base and, in the case of utilities in the Caribbean, the continuation of licences. Generally, the ability of a utility to recover the actual COS and earn the approved ROE and/or ROA depends on achieving the forecasts established in the rate-setting processes. 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 prudent cost of service and earn its allowed ROE, however, a utility is exposed to risks that inflationary increases may exceed the inflationary factor set by the regulator and that the utility may be unable to achieve productivity improvements. In the case of FortisAlberta's current PBR mechanism, there is a risk that capital expenditures may not qualify, or be approved, as a capital tracker where necessary.
Regulators approve the allowed ROEs and deemed capital structures of the utilities. Fair regulatory treatment that allows a utility to earn a fair risk-adjusted rate of return, comparable to that available on alternative investments of similar risk, is essential for maintaining service quality, as well as ongoing capital attraction and growth. Rate applications establishing revenue requirements may be subject to negotiated settlement procedures. Failing a negotiated settlement, rate applications may be pursued through a litigated public hearing process. There can be no assurance that resulting rate orders issued by the regulators will permit the regulated utilities to recover all costs actually incurred and to earn the expected or fair rates of return on an appropriate capitalization.
Electricity and gas infrastructure investments require the approval of the regulatory authorities, either through the approval of capital expenditure plans or revenue requirements for the purpose of setting electricity and gas rates, which include the impact of capital expenditures on rate base and/or COS. There is no assurance that capital projects perceived as required or completed by the Corporation's regulated utilities will be approved. Capital cost overruns may not be recoverable in customer rates.
A failure to obtain acceptable rate orders, appropriate ROEs or capital structures as applied for may adversely affect the business carried on by the regulated utilities, the undertaking or timing of capital expenditures, ratings assigned by credit rating agencies, the issuance of long-term debt and other matters, which may, in turn, have a material adverse effect on the results of operations and financial position of the Corporation's regulated utilities. In addition, there is no assurance that the regulated utilities will receive regulatory decisions in a timely manner and, therefore, costs may be incurred prior to having an approved revenue requirement.
As an owner of an electricity distribution network under the Electric Utilities Act (Alberta), FortisAlberta is required to act, or to authorize a substitute party to act, as a provider of electricity services, including the sale of electricity, to eligible customers under a regulated rate and to appoint a retailer as a default supplier to provide electricity services to customers otherwise unable to obtain electricity services. In order to remain solely a distribution utility, FortisAlberta appointed EPCOR Energy Services (Alberta) Inc. ("EPCOR") as its regulated-rate provider. As a result of this appointment, EPCOR assumed all of FortisAlberta's rights and obligations in respect of these services. In the unlikely event that EPCOR is unable or unwilling to act as a regulated-rate provider or default supplier, and no other party is willing to act in this capacity, FortisAlberta would be required to act as a provider of electricity services to eligible customers under a regulated rate or to provide electricity services to customers otherwise unable to obtain electricity services. If FortisAlberta could not secure outsourcing for these functions, it would need to administer these retail responsibilities by adding necessary staff, facilities and/or equipment.
For additional information on the nature of regulation and various regulatory matters pertaining to the Corporation's utilities, refer to the "Regulatory Highlights" section of this MD&A.
Risks Associated with the Pending Acquisition of ITC: ITC is a public company and its directors have fiduciary duties which may require them to consider competing offers to purchase the common stock of ITC as an alternative to the Acquisition. The agreement and plan of merger preserves the ability of the directors of ITC to accept a competing offer, in certain circumstances. Fortis may exercise its right to match such offer and, as a result, the purchase price could increase and other key transaction terms could change.
The closing of the acquisition of ITC, which is expected to occur in late 2016, is subject to normal commercial risks that the Acquisition will not close on the terms negotiated, or at all. Completion of the Acquisition remains subject to receipt of ITC and Fortis shareholder approvals, certain regulatory, state and federal approvals, and the satisfaction or waiver of other customary closing conditions contained in the agreement and plan of merger. The failure to obtain the required approvals or to satisfy or waive the conditions to closing may result in the termination of the agreement and plan of merger. Fortis intends to complete the Acquisition as soon as practicable after obtaining the required shareholder, regulatory and governmental approvals, and satisfying the other required closing conditions. A substantial delay in obtaining regulatory approvals or the imposition of unfavourable terms and/or conditions in such approvals could have a material adverse effect on the Corporation's ability to complete the Acquisition and on the Corporation's business, financial condition or results of operations. If the closing of the acquisition of ITC does not take place as contemplated, the Corporation could suffer material adverse consequences. Failure to complete the Acquisition would, in certain circumstances, result in the Corporation being required to pay a termination fee of up to US$280 million and other potential costs.
Fortis expects that the Acquisition will provide benefits to the Corporation, including approximately 5% accretion to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses and assuming a stable currency exchange environment. There is a risk that some or all of the expected benefits of the Acquisition may fail to materialize, or may not occur within the time periods anticipated by the Corporation. The realization of such benefits may be affected by a number of factors, many of which are beyond the control of the Corporation. Failure to realize the anticipated benefits of the acquisition of ITC may impact the financial performance of the Corporation, the price of its common shares and the ability of Fortis to continue to pay dividends on its common shares at rates consistent with the Corporation's dividend guidance, at current rates or at all.
Financing of the cash portion of the Acquisition is expected to be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of up to 19.9% of ITC to one or more infrastructure-focused minority investors. There can be no assurance that such financing sources will be available to Fortis at the desired time or at all, or on cost-efficient or commercially acceptable terms. As a result, there is no certainty that Fortis will reach a binding agreement with minority investors to complete the minority investment prior to closing of the Acquisition or at all. The Acquisition is not conditional upon Fortis securing one or more minority investors. Consummation of the Acquisition without completion of the contemplated minority investment could increase the consolidated indebtedness of the Corporation or result in the requirement for additional common equity and may have a negative impact on the Corporation's credit ratings and outlook and could result in additional financing costs and the failure to realize some, or all, of the expected benefits of the acquisition, including the extent to which the Acquisition is accretive. The Corporation obtained commitments for an aggregate of US$3.7 billion non-revolving term credit facilities. The commitments of the lenders to enter into these credit facilities is subject to certain customary conditions, which may result in such facilities becoming unavailable to Fortis in certain circumstances. If these credit facilities become unavailable, Fortis may not be able to complete the Acquisition.
While Fortis intends to become a U.S. Securities and Exchange Commission ("SEC") registrant and list its common shares on the New York Stock Exchange, there is no guarantee that it will be successful in this regard. If the Corporation is successful in this regard, it will be subject to increased regulatory compliance and may be subject to a greater risk of litigation.
The operations of ITC are conducted in US dollars and, following the Acquisition, the 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. In particular, any decrease in the value of the US dollar relative to the Canadian dollar following the Acquisition could negatively impact the Corporation's net income as reported in Canadian dollars. Fortis may enter into forward foreign exchange contracts and utilize certain other derivatives as cash flow hedges of its exposure to foreign currency risk to a greater extent than in the past. There is no guarantee that such hedging strategies, if adopted, will be effective.
Fortis expects to incur a variety of costs in 2016 associated with completing the Acquisition. The majority of these costs will be non-recurring expenses related to financing and obtaining shareholder and regulatory approvals. Certain of these costs have already been incurred and other such costs will be incurred even if the Acquisition is ultimately not completed. Additional unanticipated acquisition-related costs may also be incurred in 2016.
Interest Rate Risk: Generally, allowed ROEs for regulated utilities in North America are exposed to changes in long-term interest rates. Such rates affect allowed ROEs directly when they are applied in formulaic ROE automatic adjustment mechanisms or indirectly through a regulatory process of what constitutes an appropriate rate of return on investment, which may consider the general level of interest rates as a factor for setting allowed ROEs. Uncertainty exists regarding the duration of the current environment of low interest rates and the effect it may have on allowed ROEs of the Corporation's regulated utilities. If interest rates continue to remain at historically low levels, allowed ROEs could decrease. The continuation of a low interest rate environment could adversely affect the Corporation's ability to earn a reasonable ROE, which could have a negative effect on the financial condition and results of operations of the Corporation's regulated utilities. Also, if interest rates begin to climb, regulatory lag may cause a delay in any resulting increase in cost of capital and the regulatory allowed ROEs.
The Corporation and its subsidiaries may also be exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and refinancing of long-term debt. Central Hudson, FortisBC Energy and FortisBC Electric, however, have regulatory approval to defer any increase or decrease in interest expense resulting from fluctuations in interest rates associated with variable-rate credit facilities for recovery from, or refund to, customers in future rates. There can be no assurance that such deferral mechanisms will exist in the future, as they are dependent on future regulatory decisions. UNS Energy and Central Hudson use interest rate swaps and interest rate caps on variable-rate long-term debt to reduce risk associated with interest rates, as permitted by the regulators. At the Corporation's other regulated utilities, if the timing of issuance of, and the interest rates on, long-term debt are different from those forecast and approved in customer rates, the additional or lower interest costs incurred on the new long-term debt are not recovered from, or refunded to, customers in rates during the period that was covered by the approved customer rates. An inability to flow through interest costs to customers could have a material adverse effect on the results of operations and financial position of the utilities.
Excluding borrowings under long-term committed credit facilities, almost 90% of the Corporation's consolidated long-term debt as at December 31, 2015 had maturities beyond five years. With a significant portion of the Corporation's consolidated debt having long-term maturities, interest rate risk on debt refinancing has been reduced for the near and medium terms.
The following table outlines the nature of the Corporation's consolidated debt as at December 31, 2015.
| Total Debt | ||
| As at December 31, 2015 | ($ millions) | (%) |
| Short-term borrowings | 511 | 4.4 |
| Utilized variable-rate credit facilities classified as long term | 551 | 4.7 |
| Variable-rate long-term debt (including current portion) | 333 | 2.8 |
| Fixed-rate long-term debt (including current portion) | 10,284 | 88.1 |
| Total | 11,679 | 100.0 |
In 2015 the Corporation's regulated subsidiaries issued approximately $1 billion in long-term debt, all of which was at fixed interest rates ranging from 2.98% to 4.75%, with terms ranging from 10 to 30 years. The terms negotiated on new long-term debt demonstrate the ability of the Corporation and its utilities to raise long-term capital at attractive rates. Further information on the Corporation's consolidated long-term debt issuances is provided in the "Liquidity and Capital Resources" section of this MD&A.
A change in the level of interest rates could materially affect the measurement and disclosure of the fair value of long-term debt. The fair value of the Corporation's consolidated long-term debt, as at December 31, 2015, is provided in the "Financial Instruments" section of this MD&A.
Operating and Maintenance Risks: Storms and severe weather conditions, natural disasters, wars, terrorist acts, failure of critical equipment and other catastrophic events occurring both within and outside the service territories of the Corporation's utilities could result in service disruptions, leading to lower earnings and/or cash flows if the situation is not resolved in a timely manner or the financial impacts of restoration are not alleviated through insurance policies or regulated rate recovery. UNS Energy, Central Hudson and FortisBC Energy are exposed to various operational risks, associated with natural gas, such as: pipeline leaks, accidental damage to mains and service lines, corrosion in pipes, pipeline or equipment failure, other issues that can lead to outages and/or leaks, and any other accidents involving natural gas that could result in significant operational disruptions and/or environmental liability.
The operation of UNS Energy's electric generating stations involves certain risks, including equipment breakdown or failure, interruption of fuel supply and lower-than-expected levels of efficiency or operational performance. Unplanned outages, including extensions of planned outages due to equipment failure or other complications, occur from time to time and are an inherent risk of the generation business. There can be no assurance that the generation facilities of UNS Energy will continue to operate in accordance with expectations.
The operation of electricity T&D assets is also subject to risks, including the potential to cause fires, mainly as a result of equipment failure, falling trees and lightning strikes to lines or equipment. In addition, a significant portion of the utilities' infrastructure is located in remote areas, which may make access to perform maintenance and repairs difficult if such assets become damaged. The FortisBC utilities operate in remote and mountainous terrain with a risk of loss or damage from forest fires, floods, washouts, landslides, avalanches and other acts of nature. UNS Energy, FortisBC Energy, FortisBC Electric and the Corporation's operations in the Caribbean region are subject to risk of loss from earthquakes.
The Corporation and its subsidiaries have limited insurance that provides coverage for business interruption, liability and property damage. In the event of a large uninsured loss caused by severe weather conditions, natural disasters and certain other events beyond the control of the utility, an application would be made to the respective regulatory authority for the recovery of these costs through customer rates to offset any loss. However, there can be no assurance that the regulatory authorities would approve any such application in whole or in part. Refer to the "Business Risk Management - Insurance Coverage Risk" section of this MD&A for a further discussion on insurance.
The Corporation's electricity and gas systems require ongoing maintenance, improvement and replacement. The utilities could experience service disruptions and increased costs if they are unable to maintain their asset base. The inability to recover, through approved customer rates, the expenditures the utilities believe are necessary to maintain, improve, replace and remove assets; the failure by the utilities to properly implement or complete approved capital expenditure programs; or the occurrence of significant unforeseen equipment failures, despite maintenance programs, could have a material adverse effect on the financial position and results of operations of the Corporation's utilities.
Generally, the Corporation's utilities have designed their electricity and natural gas systems to service customers under various contingencies in accordance with good utility practice. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, processes and/or procedures to ensure the safety of employees and contractors, as well as the general public. Failure to do so may disrupt the ability of the utilities to safely distribute electricity and gas, which could have a material adverse effect on the operations of the utilities.
Economic Conditions: Typical of utilities, economic conditions, such as changes in employment levels, personal disposable income, energy prices and housing starts, in the Corporation's service territories influence energy sales. Declines in energy sales could adversely impact the respective utilities' results of operations, net earnings and cash flows.
The business of UNS Energy is concentrated in the State of Arizona. In recent years economic conditions in Arizona have contributed significantly to a reduction in retail customer growth and lower energy usage by the Company's residential, commercial and industrial customers. While it is expected that economic conditions in Arizona will improve in the future, if they do not or if they should worsen, retail customer growth rates may stagnate or decline and customers' energy usage may further decline.
FortisBC Energy is affected by the trend in housing starts from single-family dwellings to multi-family dwellings, for which natural gas has a lower penetration rate. The growth in new multi-family housing starts continues to significantly outpace that of new single-family homes, which may temper growth in gas distribution volumes.
Alberta's economy is impacted by a number of factors, including the level of oil and gas activity in the province, which is influenced by the market prices of oil and gas. A general and extended decline in economic conditions in Alberta or in other jurisdictions where the Corporation's utilities operate would be expected to have the effect of reducing demand for electricity over time. The regulated nature of utility operations, including various mitigating measures approved by certain regulators, helps reduce the impact that lower energy demand associated with poor economic conditions may have on the utilities' earnings. Significantly reduced electricity demand in the Corporation's service areas could materially reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending would, in turn, affect the Corporation's rate base and earnings growth. A severe and prolonged downturn in economic conditions could have a material adverse effect on the Corporation's results of operations, net earnings and cash flows despite regulatory measures, where applicable, available to compensate for reduced demand. In addition to the impact of reduced energy demand, an extended decline in economic conditions could also impair the ability of customers to pay for the electricity and gas they consume, thereby affecting the aging and collection of the utilities' trade receivables.
The Corporation's service territory in the Caribbean region has been impacted by challenging economic conditions over the past number of years. Activity in the tourism, real estate and construction sectors is closely tied to economic conditions in the region and changes in such activity affect customer electricity demand. Assets of Caribbean Regulated Electric Utilities comprise approximately 4% of the Corporation's total assets as at December 31, 2015.
Capital Resources and Liquidity Risk: The Corporation's financial position could be adversely affected if it and/or one of its larger subsidiaries fail 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, the regulatory environment in which the utilities operate and the nature and outcome of regulatory decisions regarding capital structure and allowed ROEs, conditions in the capital and bank credit markets, ratings assigned by credit rating agencies, and general economic conditions. Funds generated from operations after payment of expected expenses, including interest payments on any outstanding debt, may not be sufficient to fund the repayment of all outstanding liabilities when due and anticipated capital expenditures. There can be no assurance that sufficient capital will continue to be available on acceptable terms to fund capital expenditures and repay existing debt.
Consolidated fixed-term debt maturities in 2016 are expected to total $313 million. The ability to meet long-term debt repayments when due will be dependent on the Corporation and its subsidiaries obtaining sufficient and cost-effective financing. The Corporation and its utilities have been successful at raising long-term capital at reasonable rates. Activity in the global capital markets may impact the cost and timing of issuance of long-term capital by the Corporation and its subsidiaries. While the future cost of raising capital could increase, the Corporation and its subsidiaries expect to continue to have reasonable access to capital in the near to medium terms.
The cost of renewed and extended credit facilities could increase going forward. Due to their regulated nature, any forecast changes in the cost of borrowing at the utilities are eligible to be reflected in customer rates.
Generally, the Corporation and its currently rated regulated utilities are subject to financial risk associated with changes in the credit ratings assigned to them by credit rating agencies. Credit ratings affect the level of credit risk spreads on new long-term debt and credit facilities. A change in the credit ratings could potentially affect access to various sources of capital and increase or decrease finance charges of the Corporation and its utilities.
In 2015 the following changes were made to debt credit ratings of the Corporation's utilities: (i) in February 2015 Moody's Investor Service ("Moody's") upgraded the debt credit ratings of UNS Energy to 'Baa1' from 'Baa2' and TEP, UNS Electric and UNS Gas to 'A3' from 'Baa1', and (ii) in July 2015 Fitch Ratings ("Fitch") downgraded Central Hudson's debt credit rating to 'A-' from 'A' and changed the rating outlook to stable from negative. Central Hudson's debt continues to be rated 'A' by S&P and 'A2' by Moody's, both with stable outlooks. In December 2015 DBRS confirmed FortisAlberta's debt credit rating of A(low) but revised its outlook to stable from positive. Also, in August 2015 Fitch confirmed TEP's credit rating of BBB+ but revised its outlook to positive from stable and in February 2016 Fitch withdrew its rating on TEP for commercial reasons at TEP's request. 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. For details on the Corporation's credit ratings, see the "Credit Ratings" section of this MD&A.
Additional information on the Corporation's consolidated credit facilities, contractual obligations, including long-term debt maturities and repayments, and consolidated cash flow requirements is provided in the "Liquidity and Capital Resources" section of this MD&A.
Political Risk: The regulatory framework under which utilities operate is impacted by significant shifts in government policy and/or changes in governments, which create uncertainty about public policy priorities and directions, particularly around energy and environmental issues. For details related to environmental issues, refer to the "Business Risk Management - Environmental Risks" section of this MD&A.
Information Technology and Cyber-Security Risks: As operators of critical energy infrastructure, the Corporation's utilities may face a heightened risk of cyber attacks. Information technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, and other causes that can result in service disruptions, system failures, and the disclosure, deliberate or inadvertent, of confidential business and customer information. The ability of the Corporation's utilities to operate effectively is dependent upon developing and maintaining complex information systems and infrastructure that support the operation of generation and T&D facilities; provide customers with billing, consumption and load settlement information, where applicable; and support the financial and general operating aspects of the business.
The Corporation's subsidiaries have security measures, policies and controls designed to protect and secure the integrity of its information technology systems, and safeguard the confidentiality of corporate and customer information; however, cyber-security threats frequently change and require ongoing monitoring and detection capabilities. In the event the Corporation's utilities' information technology systems are breached, it could experience service disruptions, property damage, corruption or unavailability of critical data or confidential employee or customer information. If the breach is material in nature, it could adversely affect the financial performance of the Corporation, its reputation and standing with customers and regulators and expose it to claims of third-party damage. All of these factors could adversely affect the Corporation if not resolved in a timely manner, or if the financial impact of such adverse effects is not alleviated through insurance policies or, in the case of regulated utilities, through regulatory recovery.
Weather and Seasonality Risk: Fluctuations in the amount of electricity used by customers can vary significantly in response to seasonal changes in weather and could materially impact the operations, financial condition and results of operations of the electric utilities. In Canada, Arizona and New York State, cool summers may reduce air conditioning demand, while less severe winters may reduce electric heating load.
At FortisBC Energy and the gas operations of UNS Energy and Central Hudson, weather has a significant impact on gas distribution volumes as a major portion of the gas distributed is ultimately used for space heating for residential customers. Because of gas consumption patterns, the gas utilities normally generate quarterly earnings that vary by season and may not be an indicator of annual earnings. The earnings associated with regulated gas utilities are highest in the first and fourth quarters.
Regulatory deferral mechanisms are in place at certain of the Corporation's regulated utilities, including Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power, to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. The absence of the above-noted regulatory deferral mechanisms could have a material adverse effect on the results of operations and financial position of the utilities.
Natural gas and coal-fired generating plants require continuous water flow for their operation. Shifts in weather or climate patterns, seasonal precipitation, the timing and rate of melting, run off, and other factors beyond the control of the Corporation, may reduce the water flow to UNS Energy's generation facilities. Any material reduction in the water flow to UNS Energy's generation facilities would limit the ability of the Company to produce and market electricity from those respective facilities and could have a material adverse effect on the results of operations and financial position of the Corporation. Any change in regulations or the level of regulation respecting the use, treatment and discharge of water, or respecting the licensing of water rights in the jurisdictions where UNS Energy operates could result in a material adverse effect on the results of operations and financial position of the Company.
Extreme climatic factors could potentially cause government authorities to adjust water flows on the Kootenay River, where FortisBC Electric's dams and related facilities are located, in order to protect the environment. This adjustment could affect the amount of water available for generation at FortisBC Electric's plants or at plants operated by parties contracted to supply energy to FortisBC Electric. Prolonged adverse weather conditions could lead to a significant and sustained loss of precipitation over the headwaters of the Kootenay River system, which could reduce the Company's entitlement to capacity and energy under the Canal Plant Agreement.
Despite preparations for severe weather, hurricanes and other natural disasters will always remain a risk to the physical assets of utilities. Climate change, however, may have the effect of increasing the severity and frequency of weather-related natural disasters that could affect the Corporation's service territories. Although physical utility assets have been constructed and are operated and maintained to withstand severe weather, there is no assurance that they will successfully do so in all circumstances.
The assets and earnings of Caribbean Utilities, Fortis Turks and Caicos and, to a lesser extent, Central Hudson, Newfoundland Power and Maritime Electric, are subject to hurricane risk. Certain of the Corporation's utilities may also be subject to severe weather events, including ice, wind and snow storms. Weather risks are managed through insurance on generation assets, business-interruption insurance and self-insurance on T&D assets. Under its T&D licence, Caribbean Utilities may apply for a special additional customer rate in the event of a disaster such as a hurricane. Fortis Turks and Caicos does not have a specific hurricane cost-recovery mechanism; however, the Company may apply for an increase in customer rates in the following year if the actual ROA is lower than the allowed ROA due to additional costs resulting from a hurricane or other significant weather event. Central Hudson is authorized to request, and the PSC has typically approved, deferral account treatment for incremental storm restoration costs. To qualify for deferral, storm costs must meet certain criteria as stipulated by the PSC. In most cases, the Corporation's other regulated utilities can apply to their respective regulators for relief from major uncontrollable expenses, including those related to significant weather-related events.
Earnings from non-regulated generation assets in Belize are sensitive to rainfall levels. The Waneta Expansion is included in the Canal Plant Agreement and will receive fixed energy and capacity entitlements based upon long-term average water flows, thereby significantly reducing the hydrologic risk associated with hydroelectric generation. Prolonged adverse weather conditions, however, could lead to a significant and sustained loss of precipitation over the headwaters of the Kootenay River system, which could reduce the Waneta Expansion's entitlement to capacity and energy under the Canal Plan Agreement.
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 prices of electricity and natural gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of natural gas. The operation of regulator-approved deferral mechanisms to flow through in customer rates the cost of natural gas, purchased power and coal serves to mitigate the impact on earnings of commodity price volatility. The risks have also been reduced by entering into various price-risk management strategies to reduce exposure to commodity rates, including the use of derivative contracts that effectively fix the price of natural gas, power and electricity purchases. The absence of such hedging mechanism in the future could result in increased exposure to market price volatility.
Certain of the Corporation's regulated electric utilities are exposed to commodity price risk associated with changes in world oil prices, which affect the cost of fuel and purchased power. The risk is substantially mitigated by the utilities' ability to flow through to customers the cost of fuel and purchased power through base rates and/or the use of rate-stabilization and other mechanisms, as approved by the various regulatory authorities. The ability to flow through to customers the cost of fuel and purchased power alleviates the effect on earnings of the variability in the cost of fuel and purchased power.
There can be no assurance that the current regulator-approved mechanisms allowing for the flow through of the cost of natural gas, fuel, coal and purchased power will continue to exist in the future. Also, a severe and prolonged increase in such costs could materially affect FortisBC Energy, UNS Energy and Central Hudson, despite regulatory measures available to compensate for changes in these costs. The inability of the regulated utilities to flow through the full cost of natural gas, fuel and/or purchased power could have a material adverse effect on the utilities' results of operations and financial position.
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 BECOL is the US dollar.
As at December 31, 2015, the Corporation's corporately issued US$1,535 million (December 31, 2014 - US$1,496 million) long-term debt had been designated as an effective hedge of a portion of the Corporation's foreign net investments. As at December 31, 2015, the Corporation had approximately US$3,137 million (December 31, 2014 - US$2,762 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 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 balance sheet in accumulated other comprehensive income.
On an annual basis, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.38 as at December 31, 2015 would increase or decrease earnings per common share of Fortis by approximately 4 cents, before considering the impact of the pending acquisition of ITC. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where possible, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.
Counterparty Risk: UNS Energy, Central Hudson and FortisBC Energy may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The above-noted utilities deal with credit quality institutions in accordance with established credit approval practices. These utilities did not experience any counterparty defaults in 2015 and do not expect any counterparties to fail to meet their obligations.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As required under regulation, FortisAlberta minimizes its gross exposure associated with retailer billings by obtaining from the retailer either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
Competitiveness of Natural Gas in British Columbia: In FortisBC Energy's service territory, natural gas primarily competes with electricity for space and hot water heating load. Recently, there has been upward pressure on electricity rates in British Columbia, largely due to new investment required in the electricity generation and transmission sectors. In addition, the growth in North American natural gas supply, primarily from shale gas production, has resulted in a lower natural gas price environment. These factors have helped to improve natural gas competitiveness on an operating basis. Nevertheless, differences in upfront capital costs between electric and natural gas equipment for hot water and space heating applications continue to present challenges for the competitiveness of natural gas on a full-cost basis.
Government policy has also impacted the competitiveness of natural gas in British Columbia. The Government of British Columbia has introduced changes to energy policy, including greenhouse gas emission reduction targets and a consumption tax on carbon-based fuels. The Government of British Columbia has yet to introduce a carbon tax on imported electricity generated through the combustion of carbon-based fuels. The impact of these changes in energy policy may have a material impact on the competitiveness of natural gas relative to non-carbon-based energy sources or other energy sources.
There are other competitive challenges impacting the penetration of natural gas in new housing supply, such as the green attributes of the energy source and the type of housing being built. In recent years, FortisBC Energy has experienced a decline in the percentage of new homes installing natural gas compared with the total number of dwellings being built throughout British Columbia.
In the future, if natural gas becomes less competitive due to pricing or other factors, the ability of FortisBC Energy to add new customers could be impaired, and existing customers could reduce their consumption of natural gas or eliminate its usage altogether as furnaces, water heaters and other appliances are replaced. The above conditions may result in higher customer rates and, in an extreme case, could ultimately lead to an inability of FortisBC Energy to fully recover COS in rates charged to customers.
Natural Gas, Fuel and Electricity Supply: FortisBC Energy is dependent on a limited selection of pipeline and storage providers, particularly in the Lower Mainland, Interior and Vancouver Island service areas. Regional market prices, particularly at the Sumas market hub, have been higher than prices elsewhere in North America during peak winter periods, when regional pipeline and storage resources become constrained in serving the demand for natural gas in British Columbia and the U.S. Pacific Northwest. In addition, FortisBC Energy is highly dependent on a single-source transmission pipeline. In the event of a prolonged service disruption of the Spectra Pipeline System, residential customers of FortisBC Energy could experience outages, thereby affecting revenue and also resulting in costs to safely relight customers. The LNG storage facility on Vancouver Island helps to reduce this risk by providing short-term on-system supply during cold weather conditions or emergency situations.
Developments are occurring in the region that may increase the demand for gas supply from British Columbia. These include an increase in pipeline capacity to deliver gas from British Columbia to markets outside of British Columbia and the potential development of large-scale LNG facilities to export gas. British Columbia has significant natural gas resources that are expected to be sufficient to meet incremental demand requirements and to continue to supply existing markets. It is uncertain at this time, however, how the pace and location of infrastructure development to connect production to new and existing markets could impact the Corporation's access to supply at fair market prices.
The UNS Utilities are dependent on third parties to supply fuel, including natural gas and coal. Disruption of fuel supply could impair the ability of the Companies to deliver electricity or gas or generate electricity and could adversely affect operations. In addition, a loss of coal suppliers or the inability to renew existing coal or natural gas contracts at favorable terms could significantly affect the ability to serve customers and adversely affect the financial condition and the results of operations of the UNS Utilities.
Newfoundland Power is dependent on Newfoundland Hydro for approximately 93% of its customers' energy requirements and Maritime Electric is dependent on NB Power for approximately 75% of its customers' energy requirements. The Corporation's utilities in the Caribbean are dependent on third parties for the supply of all of their fuel requirements in the operation of their diesel-powered generating facilities. A shortage or interruption of the supply of electricity or fuel for the above utilities could have a material impact on their operations.
Newfoundland Power experienced losses of electricity supply from Newfoundland Hydro in January 2013 and January 2014, which disabled it from meeting all of its customers' requirements. The PUB is conducting an inquiry and hearing into these system supply issues and related power interruptions. To the extent it is able, Newfoundland Power intends to participate in these reviews in 2016. As well, the Government of Newfoundland and Labrador engaged consultants to complete an independent review of the current electricity system in the province.
Future changes in energy supply costs at Newfoundland Power, including costs associated with Nalcor Energy's Muskrat Falls hydroelectric generation development and associated transmission assets, may affect electricity prices in a manner that affects Newfoundland Power's sales. The recovery of Muskrat Falls development costs are expected to materially increase customer electricity rates.
Power Purchase and Capacity Sale Contracts: FortisBC Electric's indirect customers are served by the Company's wholesale customers, who themselves are municipal utilities. The municipal utilities may be able to obtain alternate sources of energy supply, which would result in decreased demand, higher customer rates and, in extreme cases, could ultimately lead to an inability by FortisBC Electric to fully recover its COS in customer rates.
Additionally, the Corporation's regulated electric utilities periodically enter into various power purchase contracts and resale contracts for excess capacity with third parties. Upon expiry of the contracts, there is a risk that the utilities may not be able to secure extensions of such contracts. If the contracts are not extended, there is a risk of the utilities not being able to obtain alternate supplies of similarly priced electricity or not being able to secure additional capacity resale contracts. The utilities are also exposed to risk in the event of non-performance by counterparties to the various power purchase and resale contracts.
Employee Future Benefit Plan Performance and Funding Requirements: Fortis and the majority of its subsidiaries maintain a combination of defined benefit pension and/or OPEB plans for certain of their employees. Approximately 63% of the Corporation's total employees are members of defined benefit pension plans and approximately 72% of employees are members of OPEB plans.
The employee future benefit plans are subject to judgments utilized in the actuarial determination of the projected benefit obligation and related net benefit cost. The primary assumptions utilized by management are the expected long-term rate of return on assets, the discount rate and the health care trend rate used to value the projected benefit obligation. For a discussion of the critical accounting estimates associated with employee future benefit plans, refer to the "Critical Accounting Estimates - Employee Future Benefits" section of this MD&A.
The projected benefit obligation and related net benefit cost can be affected by changes in the global financial and capital markets. There is no assurance that the employee future benefit plan assets will earn the assumed long-term rates of return. Market-driven changes impacting the performance of the employee future benefit plan assets may result in material variations from the assumed long-term rates of return on the assets, which may cause material changes in future plan funding requirements from current estimates and future net benefit cost. Market-driven changes impacting the discount rates or the health care trend rate may also result in material changes in future plan funding requirements from current estimates and future net benefit cost.
There is also risk associated with measurement uncertainty inherent in the actuarial valuation process, as it affects the measurement of net benefit cost, future funding requirements and the projected benefit obligation.
Jointly Owned and Operated Generating Units: Certain of the generating stations from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have the sole discretion or any ability to affect the management or operations at such facilities and, therefore, may not be able to ensure the proper management of the operations and maintenance of the plants. Further, TEP may have limited or no discretion in managing the changing regulations which may affect such facilities. In addition, TEP will not have sole discretion as to how to proceed with environmental compliance requirements which could require significant capital expenditures or the closure of such generating stations. A divergence in the interests of TEP and the co-owners or operators, as applicable, of such generating facilities could negatively impact the business and operations of TEP. In particular, TEP is subject to disagreement and litigation by third-party owners with respect to the existing agreements for Springerville Unit 1. As a result of these disagreements and pending litigation, the third-party owners have and may continue to refuse to pay some or all of their pro rata share of Springerville Unit 1 costs and expenses. For further details, refer to the "Critical Accounting Estimates - Contingencies" section of this MD&A.
Technology Developments and Energy Efficiency: New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to have a significant impact on retail sales, which could negatively impact various utilities' results of operations, net earnings and cash flows. Heightened awareness of energy costs and environmental concerns have increased demand for products intended to reduce consumers' use of electricity. Utilities are promoting demand-side management programs designed to help customers reduce their energy usage.
Research and development activities are ongoing for new technologies that produce power, enable more efficient storage of energy, or reduce power consumption. These technologies include renewable energy, customer-owned generation, appliances, battery storage, equipment and control systems. Advances in these, or other technologies, could have a significant impact on retail sales which could negatively impact the results of operations, net earnings and cash flows of utilities.
Environmental Risks: The Corporation's electric and gas utilities are subject to inherent environmental risks, as well as environmental laws and regulations, as discussed below.
Inherent Environmental Risks
The Corporation's electric and gas utilities are subject to inherent risks, including fires, contamination of air, soil or water from hazardous substances, natural gas emissions and emissions from the combustion of fuel required in the generation of electricity. Risks associated with fire damage are related to weather, the extent of forestation, habitation and third-party facilities located on or near the land on which the utilities' facilities are situated. The utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party claims in connection with fires on land on which its facilities are located if it is found that such facilities were the cause of a fire, and such claims, if successful, could be material. Inherent risks also include the responsibility for remediation of contaminated properties, whether or not such contamination was actually caused by the property owner. The risk of contamination of air, soil and water at the electric utilities primarily relates to the transportation, handling and storage of large volumes of fuel, the use and/or disposal of petroleum-based products, mainly transformer and lubricating oil, in the utilities' day-to-day operating and maintenance activities, and emissions from the combustion of fuel required in the generation of electricity. The risk of contamination of air, soil or water at the natural gas utilities primarily relates to natural gas and propane leaks and other accidents involving these substances. Additional risks include environmental reclamation associated with coal mines that supply generating stations in which the Corporation has an ownership interest.
The key environmental hazards related to hydroelectric generation operations include the creation of artificial water flows that may disrupt natural habitats and the storage of large volumes of water for the purpose of electricity generation.
While the Corporation and its subsidiaries maintain insurance, there can be no assurance that all possible types of liabilities that may arise related to environmental matters will be covered by insurance. For further information, refer to the "Business Risk Management - Insurance Coverage Risk" section of this MD&A.
Environmental laws and regulations
The Corporation's electric and gas utilities are subject to numerous federal, state and provincial environmental laws and regulations that may increase its cost of operations or expose it to environmental litigation and liabilities. Existing environmental laws and regulations may be revised or new environmental laws and regulations may be adopted or become applicable to the Corporation's operations. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on the results of operations of the Corporation. The utilities would request that additional costs resulting from environmental laws and regulations be recovered from customers in future rates. In addition, the process of obtaining environmental permits and approvals, including any necessary environmental assessments, can be lengthy, contentious and expensive.
The trend in environmental regulation has been to impose more restrictions and limitations on activities that may impact the environment, including the generation and disposal of wastes, the use and handling of chemical substances, and the requirement for environmental impact assessments and remediation work. It is possible that other developments may lead to increasingly strict environmental laws and enforcement policies, and claims for damages to property or persons resulting from the operations of the Corporation's subsidiaries, any one of which could result in substantial costs or liabilities to the subsidiaries.
The management of greenhouse gas emissions is a specific environmental concern of the Corporation's regulated utilities in Canada and the United States, primarily due to new and emerging federal, provincial and state greenhouse gas laws, regulations and guidelines. In British Columbia, the Government of British Columbia's Energy Plan, Carbon Tax Act, Clean Energy Act, Greenhouse Gas Reduction (Cap and Trade) Act and Greenhouse Gas Reduction Targets Act affect, or may potentially affect, the operations of FortisBC Energy and FortisBC Electric. The utilities continue to assess and monitor the impact that the Government's Energy Plan and the Clean Energy Act may have on future operations.
In August 2015 the United States Environmental Protection Agency ("EPA") issued the Clean Power Plan ("CPP") limiting carbon emissions from existing and new fossil fuelled power plants. The CPP establishes state-level carbon emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan targets carbon emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022. The CPP will require a shift in generation from coal to natural gas and renewables and could lead to the early retirement of coal generation in Arizona within the 2022 to 2030 compliance time-frame. UNS Energy is currently in the process of transitioning its generation resource mix, as appropriate, in order to reduce carbon emissions. The Company will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop compliance strategies. UNS Energy is unable to determine how the final CPP rule will impact its facilities until state plans are developed and approved by the EPA. The Company cannot predict the ultimate outcome of these matters.
The EPA incorporated the compliance obligations for existing power plants located on Indian nations, including the Navajo Nation, in the existing sources rule and a newly proposed Federal Plan using a compliance method similar to that of the states. The proposed Federal Plan would be implemented for any Indian nation and/or state that does not submit a plan or that does not have an EPA or approved state plan. UNS Energy will work with the participants at Four Corners and Navajo to determine how this revision may impact compliance and operations at the facilities. The Company has submitted comments on the proposed Federal Plan impacting its facilities, including Four Corners and Navajo stating, among other things, that the EPA should not regulate the greenhouse gases on the Navajo Nation because it is not appropriate or necessary. The reduction of greenhouse gases achieved due to the shutdowns resulting from Regional Haze compliance will be equivalent to those required under the CPP rule. UNS Energy cannot predict the ultimate outcome of these matters.
The Company's compliance requirements under the CPP are subject to the outcomes of potential proceedings and litigation challenging the rule. In February 2016 the United States Supreme Court granted a stay effectively ordering the EPA to stop CPP implementation efforts until legal challenges to the regulation have been resolved. The ruling introduces uncertainty as to whether and when the states and utilities will have to comply with the CPP. UNS Energy will continue to work with the Arizona Department of Environmental Quality to determine what, if any, actions need to be taken in light of the ruling. UNS Energy anticipates that the ruling will likely delay the requirement to submit a plan or request an extension under the CPP by September 2016.
If any of the coal-fired generation plants, or coal-handling facilities, from which UNS Energy obtains power are closed prior to the end of their useful life in response to recent or future changes in environmental regulation, the Company could be required to recognize a material impairment of its assets and incur added expenses relating to accelerated depreciation and amortization, decommissioning and cancellation of long-term coal contracts of such generating plants and facilities. Closure of any such generating stations may force UNS Energy to incur higher costs for replacement capacity and energy. The Company may not be permitted recovery of these costs in customer rates.
In addition, early closures of certain generating units could require UNS Energy to redeem some or all tax-exempt bonds associated with the respective generating units. As at December 31, 2015, approximately 43% of UNS Energy's generating capacity was fuelled by coal.
Environmental laws and regulations have given rise to environmental liabilities at certain of the Corporation's utilities. TEP is contractually obligated to pay a portion of the environmental reclamation costs incurred at generating stations in which it has an ownership interest and is obligated to pay similar costs at the coal mines that supply these generating stations. As at December 31, 2015, TEP has recognized approximately US$25 million in mine reclamation obligations, representing the present value of the estimated future liability. While TEP has recorded the portion of its obligations for such reclamation costs that can be determined at this time, the total costs and timing of final reclamation at these sites are unknown and could be substantial. TEP currently recovers final mine reclamation costs through regulator-approved mechanisms as costs are paid to the coal suppliers.
Central Hudson is exposed to environmental contingencies associated with manufactured gas plants ("MGPs") that it and its predecessors owned and operated to serve their customers' heating and lighting needs from the mid to late 1800s to the 1950s. The New York State Department of Environmental Conservation ("DEC") regulates the timing and extent of remediation of MGP sites in New York State. As at December 31, 2015, Central Hudson has recognized approximately US$92 million in associated MGP environmental remediation liabilities. As approved by the PSC, the Company is currently permitted to recover MGP site investigation and remediation costs in customer rates.
The Corporation believes that it and its subsidiaries are materially compliant with the environmental laws, regulations and guidelines applicable to them in the various jurisdictions in which they operate. With the exception of the mine reclamation costs at TEP and the MGP remediation liabilities at Central Hudson, as noted above, as at December 31, 2015, there were no material environmental liabilities recognized in the Corporation's 2015 Audited Consolidated Financial Statements. The regulated utilities would seek to recover in customer rates the costs associated with environmental protection, compliance or damages; however, there is no assurance that the regulators would agree with the utilities' requests and, therefore, unrecovered costs, if substantial, could have a material adverse effect on the results of operations and financial position of the utilities.
Insurance Coverage Risk: The Corporation and its subsidiaries maintain insurance with respect to potential liabilities and the accidental loss of value of certain of their assets, for amounts and with such insurers as is considered appropriate, taking into account all relevant factors, including practices of owners of similar assets and operations. However, a significant portion of the Corporation's regulated electric utilities' T&D assets is not covered under insurance, as is customary in North America, as the cost of coverage is not considered economically viable. Insurance is subject to coverage limits as well as time-sensitive claims discovery and reporting provisions and there can be no assurance that the types of liabilities that may be incurred by the Corporation and its subsidiaries will be covered by insurance. The Corporation's regulated utilities would likely apply to their respective regulatory authority to recover any loss or liability through increased customer rates. However, there can be no assurance that a regulatory authority would approve any such application in whole, or in part. Any major damage to the physical assets of the Corporation and its subsidiaries could result in repair costs, lost revenue and customer claims that are substantial in amount and which could have a material adverse effect on the Corporation's results of operations, cash flows and financial position. In addition, the occurrence of significant uninsured claims, claims in excess of the insurance coverage limits maintained by the Corporation and its subsidiaries, or claims that fall within a significant self-insured retention could have a material adverse effect on the Corporation's results of operations, cash flows and financial position.
It is anticipated that insurance coverage will be maintained. However, there can be no assurance that the Corporation and its subsidiaries will be able to obtain or maintain adequate insurance in the future at rates considered reasonable, or that insurance will continue to be available on terms as favourable as the existing arrangements, or that the insurance companies will meet their obligations to pay claims.
Loss of Licences and Permits: The acquisition, ownership and operation of electric and gas utilities and assets require numerous licences, permits, agreements, orders, approvals and certificates ("Approvals") from various levels of government, government agencies and third parties. For various reasons, including increased stakeholder participation, the Corporation's regulated utilities and non-regulated generation operations may not be able to obtain or maintain all required Approvals. If there is a delay in obtaining any required Approvals, or if there is a failure to obtain or maintain any required Approvals or to comply with any applicable law, regulation or condition of an approval, or there is a material change to any required Approval, the operation of the assets and the sale of electricity and gas could be prevented or become subject to additional costs, any of which could have a material adverse effect on the Corporation's subsidiaries.
Loss of Service Area: FortisAlberta serves customers residing within various municipalities throughout its service areas. From time to time, municipal governments in Alberta give consideration to creating their own electric distribution utilities by purchasing the assets of FortisAlberta located within their municipal boundaries. Upon the termination, or in the absence, of a franchise agreement, a municipality has the right, subject to AUC approval, to purchase FortisAlberta's assets within its municipal boundaries pursuant to the Municipal Government Act (Alberta), with the price to be as agreed by the Company and the municipality, failing which it is to be determined by the AUC. Additionally, under the Hydro and Electric Energy Act (Alberta), if a municipality that owns an electric distribution system expands its boundaries, it can acquire FortisAlberta's assets in the annexed area. In such circumstances, the Hydro and Electric Energy Act (Alberta) provides that the AUC may determine that the municipality should pay compensation to the Company for any facilities transferred on the basis of replacement cost less depreciation. Given the historical population and economic growth of Alberta and its municipalities, FortisAlberta is affected by transactions of this type from time to time.
Within certain portions of the FortisAlberta's service territory, REAs have been granted by the AUC the right to provide electric distribution service to their eligible members. Members eligible to receive electric distribution service from an REA are those who meet the specific eligibility criteria defined in the integrated operating agreements between the Company and REA. In general, this eligibility criteria has limited the provision of service to customers whose land is used for agricultural activity or as a rural estate property. This historical arrangement has been challenged by some self-operating REAs that are seeking to expand their services to a broader range of customers within the service area that overlaps that of the Company. FortisAlberta is actively resisting these efforts on the part of these self-operated REAs, as it believes the legislative scheme in Alberta does not support this type of competition between the regulated utility and these small rural electricity cooperatives. There is a risk that the efforts of these self-operating REAs to expand their services to a broader range of customers could increase their ability to serve customers in competition with the Company.
The consequence to FortisAlberta of a municipality purchasing its distribution assets or an REA serving more customers in its service territory would be an erosion of the Company's rate base, which would reduce the capital upon which FortisAlberta could earn a regulated return. A significant reduction of rate base could have a material adverse effect on the results of operations and financial position of FortisAlberta.
Continued Reporting in Accordance with US GAAP: In January 2014 the Ontario Securities Commission ("OSC") issued a relief order which permits the Corporation and its reporting issuer subsidiaries in Canada to continue to prepare their financial statements in accordance with US GAAP until the earliest of: (i) January 1, 2019; (ii) the first day of the financial year that commences after the Corporation or its reporting issuer subsidiaries ceases to have activities subject to rate regulation; or (iii) the effective date prescribed by the International Accounting Standards Board ("IASB") for the mandatory application of a standard within International Financial Reporting Standards ("IFRS") specific to entities with activities subject to rate regulation.
If the OSC relief does not continue as detailed above, the Corporation and its reporting issuer subsidiaries would then be required to become SEC registrants in order to continue reporting under US GAAP, or adopt IFRS. The IASB has released an interim, optional standard on Regulatory Deferral Accounts and continues to work on a project focusing on accounting specific to rate-regulated activities. It is not yet known when this project will be completed or whether IFRS will, as a result, include a permanent, mandatory standard to be applied by entities with activities subject to rate regulation. In the absence of a permanent standard for rate-regulated activities, the application of IFRS could result in volatility in the Corporation's earnings and earnings per common share as compared to those which would otherwise be recognized under US GAAP. In connection with the pending acquisition of ITC, Fortis expects to become a registrant with the SEC. As an SEC registrant, Fortis would be entitled under applicable Canadian laws to continue to prepare its consolidated financial statements in accordance with US GAAP.
Changes in Tax Legislation: The Corporation and its subsidiaries are subject to changes in tax legislation in Canada, the United States and other international jurisdictions.
Canadian Tax Legislation
During 2015 there were elections at the federal level and several provincial jurisdictions in Canada. A change in government can result in the passing of new tax legislation, including a change in rates of taxation. The new federal and provincial budgets are expected to be delivered in early 2016 and any resulting changes could have an impact on the Corporation and its Canadian subsidiaries. Any changes in tax legislation could affect the Corporation's results of operations, cash flows and financial position.
U.S. Tax Legislation
In 2015 the U.S. Congress enacted legislation approving the use of bonus depreciation through to 2019, subject to a phase out schedule reducing allowable rates to 50% in 2015 through 2017, 40% in 2018 and 30% in 2019. While this legislation provides greater certainty for planning purposes and reduces the cash tax burden of the Corporation's subsidiaries in the United States, any changes in this or other tax legislation in the United States could affect the Corporation's results of operations, cash flows and financial position.
International Tax Legislation
Fortis conducts business in certain tax-free jurisdictions, including certain countries in the Caribbean and Belize. Canada requires the governments of certain tax-free jurisdictions to enter a Tax Information Exchange Agreement ("TIEA"), which permits dividends paid from those jurisdictions to be exempt from tax when received in Canada. This legislation allows Fortis to receive a tax-free return of capital from the Caribbean. Certain legislation also provides a mechanism for the repayment of upstream loans that were previously used as a tax-deferred repatriation of earnings. The Corporation has approximately $79 million of upstream loans from its Caribbean subsidiaries, which are required to be repaid by August 2016. The Corporation expects to repay these loans, as required.
A TIEA has not yet been negotiated between Canada and Belize and there are no indications that Canada will conclude negotiations with the GOB in the near future. Until a TIEA is in place, active business earnings in Belize cannot be repatriated to Canada on a tax-free basis; however, the GOB has signed on to the Convention on Mutual Administrative Assistance in Tax Matter, which excludes Belize as a "non-qualifying country". As a result, the Corporation is not required to accrue tax on its active business income from Belize, whether or not repatriated to Canada.
In October 2015 the Organization for Economic Co-operation and Development ("OECD") released its final reports in connection with its action plan to address Base Erosion and Profit Sharing ("BEPS Action Plan"). The basis of the BEPS Action Plan is to identify and curb aggressive tax planning and practices, as well as monitor the international tax systems. Canada has not yet implemented the recommendations of the OECD report into tax treaties and domestic law; however, if it were to be enacted under Canadian tax legislation the Corporation would be required to assess the impacts and determine whether any changes to existing tax practices are required.
Access to First Nations' Lands: FortisBC Energy and FortisBC Electric provide service to customers on First Nations' lands and maintain gas facilities and electric generation and T&D facilities on lands that are subject to land claims by various First Nations. A treaty negotiation process involving various First Nations and the governments of British Columbia and Canada is underway, but the basis upon which settlements might be reached in the service areas of FortisBC Energy and FortisBC Electric is not clear. Furthermore, not all First Nations are participating in the process. To date, the policy of the Government of British Columbia has been to endeavour to structure settlements without prejudicing existing rights held by third parties, such as FortisBC Energy and FortisBC Electric. However, there can be no certainty that the settlement process will not have a material adverse effect on FortisBC Energy and FortisBC Electric's results of operations and financial position.
The Supreme Court of Canada decided in 2010 that, before issuing regulatory approvals for the addition of new facilities, the BCUC must consider whether the Crown has a duty to consult and accommodate First Nations, if necessary, and if so, whether the consultation and accommodation by the Crown have been adequate. This may affect the timing, cost and likelihood of the BCUC's approval of certain capital projects of FortisBC Energy and FortisBC Electric.
FortisAlberta has distribution assets on First Nations' lands with access permits to these lands held by TransAlta Utilities Corporation ("TransAlta"). In order for FortisAlberta to acquire these access permits, both the Department of Aboriginal Affairs and Northern Development Canada and the individual First Nations band councils must grant approval. FortisAlberta may not be able to acquire the access permits from TransAlta and may be unable to negotiate land-use agreements with property owners or, if negotiated, such agreements may be on terms that are less than favourable to the Company and, therefore, may have a material adverse effect on FortisAlberta.
Labour Relations Risk: The Corporation's subsidiaries employ members of labour unions or associations that have entered into collective bargaining agreements with the subsidiaries. The Corporation considers the relationships of its subsidiaries with their labour unions and associations to be satisfactory but there can be no assurance that current relations will continue in the future or that the terms under the present collective bargaining agreements will be renewed. The inability to maintain or renew the collective bargaining agreements on acceptable terms could result in increased labour costs or service interruptions arising from labour disputes that are not provided for in approved rate orders at the regulated utilities and which could have a material adverse effect on the results of operations, cash flows and financial position of the utilities.
Human Resources Risk: The ability of Fortis to deliver service in a cost-effective manner is dependent on the ability of the Corporation's subsidiaries to attract, develop and retain skilled workforces. Like other utilities across Canada and in the United States and the Caribbean, the Corporation's utilities are faced with demographic challenges relating to trades, technical staff and engineers. The growing size of the Corporation and a competitive job market present ongoing recruitment challenges. The Corporation's significant consolidated capital expenditure program will present challenges to ensure the Corporation's utilities have the qualified workforce necessary to complete the capital work initiatives.
CHANGES IN ACCOUNTING POLICIES
The new US GAAP accounting policies that are applicable to, and were adopted by, Fortis, effective during 2015, are described as follows.
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
The Corporation prospectively adopted Accounting Standards Update ("ASU") No. 2014-08 that changes the criteria and disclosures for reporting discontinued operations. As a result, the sale of commercial real estate and hotel assets and the sale of non-regulated generation assets in 2015 did not meet the criteria for discontinued operations. The sales are consistent with the Corporation's focus on its core utility business and, therefore, do not represent a strategic shift in operations.
Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period
The Corporation early adopted ASU No. 2014-12 that resolves diversity in practice for employee share-based payments with performance targets that can entitle an employee to benefit from an award regardless of if they are rendering services at the date the performance target is achieved. The adoption of this update was applied prospectively and did not have a material impact on the Corporation's 2015 Audited Consolidated Financial Statements.
Simplifying the Presentation of Debt Issuance Costs
The Corporation early adopted ASU No. 2015-03 that requires debt issuance costs to be presented on the consolidated balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The adoption of this update was applied retrospectively and resulted in the reclassification of debt issuance costs of approximately $65 million from long-term other assets to long-term debt on the Corporation's consolidated balance sheet as at December 31, 2014. Additionally, the Corporation early adopted ASU No. 2015-15 that clarifies the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements. The update permits an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The adoption of this update was applied retrospectively and did not have a material impact on the Corporation's consolidated financial statements.
Balance Sheet Classification of Deferred Taxes
The Corporation early adopted ASU No. 2015-17 that requires deferred tax assets and liabilities to be classified and presented as long term on the consolidated balance sheet. The adoption of this update was applied retrospectively and resulted in the reclassification of current deferred income taxes assets of $158 million, long-term deferred income tax assets of $62 million, and current deferred income tax liabilities of $9 million to long-term deferred income tax liabilities on the consolidated balance sheet as at December 31, 2014. As a result, the Corporation also reclassified current regulatory assets of $18 million, current regulatory liabilities of $19 million, and long-term regulatory liabilities of $91 million, to long-term regulatory assets on the consolidated balance sheet as at December 31, 2014, all associated with regulatory deferred income taxes.
FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create ASC Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard completes a joint effort by FASB and the IASB to improve financial reporting by creating common revenue recognition guidance for US GAAP and IFRS that clarifies the principles for recognizing revenue and that can be applied consistently across various transactions, industries and capital markets. This standard was originally effective for annual and interim periods beginning after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. ASU No. 2015-14 was issued in August 2015 and the amendments in this update defer the effective date of ASU No. 2014-09 by one year to annual and interim periods beginning after December 15, 2017. Early adoption is permitted as of the original effective date. The majority of the Corporation's revenue is generated from energy sales to customers based on published tariff rates, as approved by the respective regulators, and is expected to be in the scope of ASU No. 2014-09. Fortis has not yet selected a transition method and is assessing the impact that the adoption of this standard will have on its consolidated financial statements and related disclosures. The Corporation plans to have this assessment substantially complete by the end of 2016.
Amendments to the Consolidation Analysis
ASU No. 2015-02 was issued in February 2015 and 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 with regard to 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. This update is effective for annual and interim periods beginning after December 15, 2015 and may be applied using a modified retrospective approach or retrospectively. The adoption of this update is not expected to materially impact the Corporation's consolidated financial statements, however, it is expected to change the Corporation's 51% controlling ownership interest in Waneta Partnership from a voting interest entity to a variable interest entity, resulting in additional note disclosure.
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 | 2015 | 2014 | ||
| Liability as at December 31 | Carrying | Estimated | Carrying | Estimated |
| ($ millions) | Value | Fair Value | Value | Fair Value |
| Waneta Partnership promissory note | 56 | 59 | 53 | 56 |
| Long-term debt, including current portion | 11,240 | 12,614 | 10,501 | 12,237 |
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.
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.
| Financial Instruments Carried at Fair Value | |||||
| As at December 31 | Fair value | ||||
| ($ millions) | hierarchy | 2015 | 2014 | ||
| Assets | |||||
| Energy contracts subject to regulatory deferral (1) (2) (3) | Levels 2/3 | 7 | 3 | ||
| Energy contracts not subject to regulatory deferral (1) (2) | Level 3 | 2 | 1 | ||
| Available-for-sale investment (4) (5) | Level 1 | 33 | - | ||
| Assets held for sale | Level 2 | 9 | - | ||
| Other investments (4) | Level 1 | 12 | 5 | ||
| Total gross assets | 63 | 9 | |||
| Less: Counterparty netting not offset on the balance sheet (6) | (6 | ) | (3 | ) | |
| Total net assets | 57 | 6 | |||
| Liabilities | |||||
| Energy contracts subject to regulatory deferral (1) (2) (7) | Levels 1/2/3 | 78 | 72 | ||
| Energy contracts not subject to regulatory deferral (1) (2) | Level 3 | - | 1 | ||
| Energy contracts - cash flow hedges (2) (8) | Level 3 | - | 1 | ||
| Interest rate swaps - cash flow hedges (8) | Level 2 | 5 | 5 | ||
| Total gross liabilities | 83 | 79 | |||
| Less: Counterparty netting not offset on the balance sheet (6) | (6 | ) | (3 | ) | |
| Total net liabilities | 77 | 76 | |||
| (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 rates as permitted by the regulators, with the exception of long-term wholesale trading contracts. |
| (2) | Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term wholesale trading contracts and those that qualify as cash flow hedges. |
| (3) | Includes $2 million - level 2 and $5 million - level 3 (2014 - $3 million - level 3) |
| (4) | Included in long-term other assets on the consolidated balance sheet |
| (5) | The cost of the available-for-sale investment was $35 million 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. |
| (6) | 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. |
| (7) | Includes $1 million - level 1, $52 million - level 2 and $25 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3) |
| (8) | The fair value of certain of the Corporation's energy contracts are recorded in accounts payable and other current liabilities and the fair value of the Corporation's interest rate swaps are recorded in accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value are recorded in other comprehensive income until they become realized and are reclassified to earnings. |
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts and gas swap and option contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships and transmission and line losses. The fair value of gas option contracts is estimated using a Black-Scholes option-pricing model, which includes inputs such as implied volatility, interest rates, and forward price curves. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
Central Hudson holds electricity swap contracts and gas swap and option contracts to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair value of the electricity swap contracts and gas swap and option contracts was calculated using forward pricing provided by independent third parties.
FortisBC Energy holds gas purchase 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 December 31, 2015, 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 December 31, 2015, unrealized losses of $74 million (December 31, 2014 - $69 million) were recognized in regulatory assets and unrealized gains of $3 million were recognized in regulatory liabilities.
Energy Contracts Not Subject to Regulatory Deferral
In June 2015 UNS Energy entered into long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with the ratepayer through UNS Energy's rate stabilization accounts.
Cash Flow Hedges
UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on lease debt, and held a power purchase swap, that expired in September 2015, to hedge the cash flow risk associated with a long-term power supply agreement. The after-tax unrealized gains and losses on cash flow hedges are recorded in other comprehensive income and reclassified to earnings as they become realized. The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $1 million.
Central Hudson holds interest rate cap contracts expiring in 2016 and 2017 on bonds with a total principal amount of US$64 million. Variations in the interest costs of the bonds, including any gains or losses associated with the interest rate cap contracts, are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator and do not impact earnings.
Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.
Volume of Derivative Activity
As at December 31, 2015, 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) | 2019 | 8 | 1,043 | 730 | 438 | 219 | - | - | |
| Electricity power purchase contracts (GWh) | 2017 | 28 | 1,027 | 145 | - | - | - | - | |
| Gas swap and option contracts (PJ) | 2018 | 154 | 40 | 10 | 4 | - | - | - | |
| Gas purchase contract premiums (PJ) | 2024 | 89 | 91 | 42 | 38 | 22 | 22 | 64 | |
| Energy contracts not subject to regulatory deferral: | |||||||||
| Long-term wholesale trading contracts (GWh) | 2016 | 6 | 1,310 | - | - | - | - | - | |
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's 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. 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. The Corporation's critical accounting estimates are discussed as follows.
Regulation: Generally, the accounting policies of the Corporation's regulated utilities are subject to examination and approval by the respective regulatory authority. Regulatory assets and regulatory liabilities arise as a result of the rate-setting process at the regulated utilities and have been recognized based on previous, existing or expected regulatory orders or decisions. Certain estimates 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. The final amounts approved by the regulatory authorities for deferral as regulatory assets and regulatory liabilities and the approved recovery or settlement periods may differ from those originally expected. Any resulting adjustments to original estimates 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.
As at December 31, 2015, Fortis recognized a total of $2,532 million in regulatory assets (December 31, 2014 - $2,415 million) and $1,638 million in regulatory liabilities (December 31, 2014 - $1,445 million).
For a further discussion of the nature of regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Depreciation and Amortization: Depreciation and amortization are estimates based primarily on the useful life of assets. Estimated useful lives are based on current facts and historical information and take into consideration the anticipated physical life of the assets. As at December 31, 2015, the Corporation's consolidated capital assets and intangible assets were approximately $20.1 billion, or approximately 70%, of total consolidated assets compared to approximately $18.3 billion, or approximately 70%, of total consolidated assets as at December 31, 2014. Depreciation and amortization was $873 million for 2015 compared to $688 million for 2014.
As required by their respective regulator, UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, Newfoundland Power and Maritime Electric accrue estimated non-asset retirement obligation ("ARO") removal costs in depreciation, with the amount provided for in depreciation recorded as a long-term regulatory liability. Actual non-ARO removal costs are recorded against the regulatory liability when incurred. The estimate of non-ARO removal costs is based on historical experience and expected cost trends. The balance of this regulatory liability as at December 31, 2015 was $1,060 million, an increase of $109 million from $951 million as at December 31, 2014, mainly due to the impact of foreign exchange associated with the translation of US dollar-denominated non-ARO removal cost liabilities.
Changes in depreciation rates, resulting from a change in the estimated service life or removal costs, could have a significant impact on the Corporation's consolidated depreciation and amortization expense.
As part of the customer rate-setting process at the Corporation's regulated utilities, appropriate depreciation, amortization and removal cost rates, as applicable, are approved by the respective regulatory authority. The depreciation periods used and the associated rates are reviewed on an ongoing basis to ensure they continue to be appropriate. From time to time, third-party depreciation studies are performed at the regulated utilities. Based on the results of these depreciation studies, the impact of any over- or under-depreciation, as a result of actual experience differing from that expected and provided for in previous depreciation rates, is generally reflected in future depreciation rates and depreciation expense, when the differences are refunded or collected in customer rates, as approved by the regulator.
Effective January 1, 2015, FortisAlberta's depreciation and amortization rates were changed as a result of a technical update to its last depreciation study, which was completed as of December 31, 2010. A technical update adjusts depreciation and amortization rates based on current capital asset balances, while retaining the depreciation parameters established in the last approved depreciation study. As a result, FortisAlberta's depreciation and amortization expense were reduced by approximately $7 million in 2015.
Income Taxes: Income taxes are determined based on estimates of the Corporation's current income taxes and estimates of deferred income taxes resulting from temporary differences between the carrying values of assets and liabilities in the consolidated financial statements and their tax values. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. Deferred income tax assets are assessed for the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered more likely than not, a valuation allowance is recognized against earnings in the period when the allowance is created or revised. Estimates of the provision for current income taxes, deferred income tax assets and liabilities, and any related valuation allowance, might vary from actual amounts incurred.
Assessment for Impairment of Goodwill and Indefinite-Lived Intangible Assets: The Corporation is required to perform, at least on an annual basis, an impairment test for goodwill and indefinite-lived intangible assets, and any impairment provision is charged to earnings. The annual impairment test is performed as at October 1. In addition, the Corporation also performs an impairment test if any event occurs or if circumstances change that would indicate that the fair value of a reporting unit was below its carrying value. No such event or change in circumstances occurred during 2015 or 2014.
As at December 31, 2015, consolidated goodwill totalled approximately $4.2 billion (December 31, 2014 - $3.7 billion). Indefinite-lived intangible assets, not subject to amortization, consist of certain land, transmission and water rights and totalled approximately $106 million as at December 31, 2015 (December 31, 2014 - $77 million).
Fortis performs an annual internal quantitative assessment for each reporting unit. For those reporting units where: (i) management's assessment of quantitative and qualitative factors indicates that fair value is not 50% or more likely to be greater than carrying value; or (ii) the excess of estimated fair value over carrying value, as determined by an external consultant as of the date of the immediately preceding impairment test, was not significant, then fair value of the reporting unit will be estimated by an external consultant in the current year. Irrespective of the above-noted approach, a reporting unit to which goodwill has been allocated may have its fair value estimated by an external consultant as at the annual impairment date, as Fortis will, at a minimum, have fair value for each material reporting unit estimated by an external consultant once every five years.
In calculating goodwill impairment, Fortis determines those reporting units that will have fair value estimated by an external consultant, as described above, and such estimated fair value is then compared to the book value of the applicable reporting units. If the fair value of the reporting unit is less than the book value, then a second measurement step is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill, and then comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of the goodwill over the implied fair value is the impairment amount recognized.
The primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value approach. Under the enterprise value approach, sustainable cash flow is determined on an after-tax basis, prior to the deduction of interest expense, and is then discounted at the weighted average cost of capital to yield the value of the enterprise. An enterprise value approach does not assess the appropriateness of the reporting unit's existing debt level. The estimated fair value of the reporting unit is then determined by subtracting the fair value of the reporting unit's interest-bearing debt from the enterprise value of the reporting unit. A secondary valuation method, the market approach, is also performed by an external consultant as a check on the conclusions reached under the income approach. The market approach includes comparing various valuation multiples underlying the discounted cash flow analysis of the applicable reporting units to trading multiples of guideline entities and recent transactions involving guideline entities, recognizing differences in growth expectations, product mix and risks of those guideline entities with the applicable reporting units.
No impairment provisions were required in either 2015 or 2014 with respect to goodwill or indefinite-lived intangible assets.
Employee Future Benefits:
Defined Benefit Pension Plans
The Corporation's and subsidiaries' defined benefit pension plans are subject to judgments utilized in the actuarial determination of the net benefit cost and related obligation. The main assumptions utilized by management in determining the net benefit cost and obligation are the discount rate for the benefit obligation and the expected long-term rate of return on plan assets.
The expected weighted average long-term rate of return on the defined benefit pension plan assets, for the purpose of estimating net pension cost for 2016, is 6.17%, which is down from 6.25% used for 2015. The decrease in the average long-term rate of return reflects shifting of plan assets from equities to fixed income assets. The defined benefit pension plan assets experienced total positive returns of approximately $30 million in 2015 compared to expected positive returns of $140 million. The expected long-term rates of return on pension plan assets are developed by management with assistance from independent actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.
The assumed weighted average discount rate used to measure the projected benefit obligations as at December 31, 2015, and to determine net pension cost for 2016, is 4.21%, compared to the assumed weighted average discount rate used to measure the projected benefit obligations as at December 31, 2014, and to determine net pension cost for 2015, of 4.00%. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected pension payments. The methodology in determining the discount rates was consistent with that used to determine the discount rates in the previous year, except as follows for UNS Energy. UNS Energy adopted the spot rate methodology for determining net pension cost for 2016.
There was a $26 million increase in consolidated defined benefit net pension cost for 2015 compared to 2014, mainly due to the acquisition of UNS Energy in August 2014, and foreign currency translation impacts. Any increases in defined benefit net pension cost at the regulated utilities for 2016 are expected to be recovered from customers in rates, subject to regulatory lag and forecast risk at certain of the utilities.
The following table provides the sensitivities associated with a 100 basis point change in the expected long-term rate of return on pension plan assets and the discount rate on 2015 net benefit pension cost, and the related projected benefit obligation recognized in the Corporation's 2015 Audited Consolidated Financial Statements.
| Sensitivity Analysis of Changes in Rate of Return on Plan Assets and Discount Rate | ||||
| Year Ended December 31, 2015 (Decrease) increase ($ millions) |
Net pension benefit cost |
Projected benefit obligation (1) |
||
| Impact of increasing the rate of return assumption by 100 basis points | (24 | ) | - | |
| Impact of decreasing the rate of return assumption by 100 basis points | 20 | (44 | ) | |
| Impact of increasing the discount rate assumption by 100 basis points | (44 | ) | (370 | ) |
| Impact of decreasing the discount rate assumption by 100 basis points | 51 | 469 | ||
| (1) | At FortisBC Energy and FortisBC Electric, certain defined benefit pension plans have pension indexing provisions which provide for a portion of investment returns to be allocated in order to provide for indexing of pension benefits. Therefore, a change in the expected long-term rate of return on pension plan assets has an impact on the projected benefit obligation. The direction of the impact of a change in the rate of return assumption at FortisBC Energy and FortisBC Electric is also the result of the methodology for determining the pension indexing assumption. |
Other assumptions applied in measuring net benefit pension cost and/or the projected benefit obligation include the average rate of compensation increase, average remaining service life of the active employee group, and employee and retiree mortality rates.
As approved by the regulator, the cost of defined benefit pension plans at FortisAlberta is recovered in customer rates based on the cash payments made. Any difference between the cash payments made during the year and the cost incurred during the year is deferred as a regulatory asset or regulatory liability. Therefore, changes in assumptions result in changes in regulatory assets and regulatory liabilities for FortisAlberta. Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms to defer variations in net pension cost from forecast net pension cost, used to set customer rates, as a regulatory asset or regulatory liability. There can be no assurance, however, that the above-noted deferral mechanisms will continue in the future as they are dependent on future regulatory decisions and orders.
As at December 31, 2015, for all defined benefit pension plans, the Corporation had consolidated projected benefit obligations of $2,828 million (December 31, 2014 - $2,604 million) and consolidated plan assets of $2,466 million (December 31, 2014 - $2,216 million), for a consolidated funded status in a liability position of $362 million (December 31, 2014 - $388 million). During 2015, the Corporation recognized consolidated net pension benefit cost of $97 million (2014 - $71 million).
OPEB Plans
The OPEB plans of the Corporation and its subsidiaries are also subject to judgments utilized in the actuarial determination of the cost and the accumulated benefit obligation. Similar assumptions as described above, except for the assumption of the expected long-term rate of return on pension plan assets, which is applicable only to the OPEB plans at UNS Energy and Central Hudson, along with the health care cost trend rate, were also utilized by management in determining net OPEB cost and accumulated benefit obligation.
The OPEB plan assets at UNS Energy and Central Hudson experienced no returns in 2015 compared to expected positive returns of approximately $12 million.
The following table provides the sensitivities associated with a 100 basis point change in the health care cost trend rate and the discount rate on 2015 net OPEB cost, and the related consolidated accumulated benefit obligation recognized in the Corporation's 2015 Audited Consolidated Financial Statements.
| Sensitivity Analysis of Changes in Health Care Cost Trend Rate and Discount Rate | ||||
| Year Ended December 31, 2015 Increase (decrease) ($ millions) |
Net OPEB cost |
Accumulated benefit obligation |
|
|
| Impact of increasing the health care cost trend rate assumption by 100 basis points | 7 | 51 | ||
| Impact of decreasing the health care cost trend rate assumption by 100 basis points | (5 | ) | (43 | ) |
| Impact of increasing the discount rate assumptionby 100 basis points | (6 | ) | (71 | ) |
| Impact of decreasing the discount rate assumptionby 100 basis points | 9 | 85 | ||
Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator-approved mechanisms to defer variations in net OPEB cost from forecast net OPEB cost, used to set customer rates, as a regulatory asset or regulatory liability. There can be no assurance, however, that the above-noted deferral mechanisms will continue in the future as they are dependent on future regulatory decisions and orders.
As at December 31, 2015, for all OPEB plans, the Corporation had consolidated accumulated benefit obligations of $574 million (December 31, 2014 - $564 million) and consolidated plan assets of $181 million (December 31, 2014 - $154 million), for a consolidated funded status in a liability position of $393 million (December 31, 2014 - $410 million). During 2015, the Corporation recognized consolidated net OPEB benefit cost of $27 million (2014 - $21 million).
AROs: The measurement of the fair value of AROs requires making reasonable estimates concerning the method of settlement and settlement dates associated with the legally obligated asset retirement costs. There are also uncertainties in estimating future asset retirement costs due to potential external events, such as changing legislation or regulations and advances in remediation technologies. While the Corporation has AROs associated with hydroelectric generating facilities, interconnection facilities, removal of certain distribution system assets from rights-of-way at the end of the life of the systems and the remediation of certain land, no amounts were recognized as at December 31, 2015 and 2014, with the exception of AROs recognized by UNS Energy, Central Hudson and FortisBC Electric.
The nature, amount and timing of costs associated with land and environmental remediation and/or removal of assets cannot be reasonably estimated at this time as the hydroelectric generation and T&D assets are reasonably expected to operate in perpetuity due to the nature of their operation; applicable licences, permits and interconnection facilities agreements are reasonably expected to be renewed or extended indefinitely to maintain the integrity of the related assets and ensure the continued provision of service to customers; a land-lease agreement is expected to be renewed indefinitely; and the exact nature and amount of land remediation is indeterminable. In the event that environmental issues are known and identified, assets are decommissioned or the applicable licences, permits, agreements or leases are terminated, AROs will be recognized at that time provided the costs can be reasonably estimated and are material.
As at December 31, 2015, the Corporation's total AROs were $49 million (December 31, 2014 - $37 million). UNS Energy's AROs were primarily associated with TEP's generation and photovoltaic assets; Central Hudson's AROs were primarily associated with asbestos remediation; and FortisBC Electric's AROs were associated with the removal of polychlorinated biphenyl ("PCB")-contaminated oil from electrical equipment. The total ARO liability as at December 31, 2015 has been classified on the consolidated balance sheet as a long-term other liability with the offset to utility capital assets. All factors used in estimating the companies' AROs represent management's best estimate of the fair value of the costs required to meet existing legislation or regulations. It is reasonably possible that volumes of contaminated assets, inflation assumptions, cost estimates to perform the work and the assumed pattern of annual cash flows may differ significantly from the companies' current assumptions. The AROs may change from period to period because of changes in the estimation of these uncertainties. Other subsidiaries also affected by AROs associated with the removal of PCB-contaminated oil from electrical equipment include Central Hudson, FortisAlberta, Newfoundland Power, FortisOntario and Maritime Electric. As at December 31, 2015, the AROs related to PCBs for the above-noted utilities were not material and, therefore, were not recognized.
Revenue Recognition: Revenue at the Corporation's regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon delivery to customers and is recognized as revenue using approved rates when consumed. Meters are read periodically and bills are issued to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have been billed. Electricity and gas that is consumed but not yet billed to customers is estimated and accrued as revenue at each period end, as approved by the regulator. Effective July 1, 2015, Central Hudson is permitted by the regulator to accrue unbilled revenue for electricity consumed at each period end for all of its electricity customers. As at December 31, 2014, approximately $15 million (US$13 million) in unbilled revenue at Central Hudson, associated with certain electricity customers, was not accrued, as permitted by the regulator.
The unbilled revenue accrual for the period is based on estimated electricity and gas sales to customers for the period since the last meter reading at the rates approved by the respective regulatory authority. The development of the electricity and gas sales estimates generally requires analysis of consumption on a historical basis in relation to key inputs, such as the current price of electricity and gas, population growth, economic activity, weather conditions and system losses. The estimation process for accrued unbilled electricity and gas consumption will result in adjustments of electricity and gas revenue in the periods they become known, when actual results differ from the estimates. As at December 31, 2015, the amount of accrued unbilled revenue recognized in accounts receivable was approximately $404 million (December 31, 2014 - $365 million) on consolidated revenue of $6,727 million for 2015 (2014 - $5,401 million). The increase in accrued unbilled revenue from December 31, 2014 was primarily due to the impact of foreign exchange on the translation of US dollar-denominated unbilled revenue accruals.
Capitalized Overhead: As required by their respective regulator, UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos capitalize overhead costs that are not directly attributable to specific utility capital assets but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized general overhead costs to utility capital assets is established by the respective regulator. Any change in the methodology of calculating and allocating general overhead costs to utility capital assets could have a material impact on the amount recognized as operating expenses versus utility capital assets.
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 or results of operations.
The following describes the nature of the Corporation's contingencies.
UNS Energy
Springerville Unit 1
In November 2014 the Springerville Unit 1 third-party owners filed a complaint ("FERC Action") against TEP with FERC, alleging that TEP had not agreed to wheel power and energy for the third-party owners in the manner specified in the existing Springerville Unit 1 facility support agreement between TEP and the third-party owners and for the cost specified by the third-party owners. The third-party owners requested an order from FERC requiring such wheeling of the third-party owners' energy from their Springerville Unit 1 interests beginning in January 2015 for the price specified by the third-party owners. In February 2015 FERC issued an order denying the third-party owners' complaint. In March 2015 the third-party owners filed a request for rehearing in the FERC Action, which FERC denied in October 2015. In December 2015 the third-party owners appealed FERC's order denying the third-party owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015 TEP filed an unopposed motion to intervene in the Ninth Circuit appeal.
In December 2014 the third-party owners filed a complaint ("New York Action") against TEP in the Supreme Court of the State of New York, New York County. In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged and the court's subsequent ruling on the motions, the third-party owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; and that TEP breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses. The third amended complaint seeks US$71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The third-party owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015 the third-party owners filed a motion for summary judgment on their claim that TEP failed to pay certain of the third-party owners' claimed expenses.
In December 2014 and January 2015, Wilmington Trust Company, as owner trustees and lessors under the leases of the third-party owners, sent notices to TEP that alleged that TEP had defaulted under the third-party owners' leases. The notices demanded that TEP pay liquidated damages totalling approximately US$71 million. In letters to the owner trustees, TEP denied the allegations in the notices.
In April 2015 TEP filed a demand for arbitration with the American Arbitration Association ("AAA") seeking an award of the owner trustees and co-trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015 the third-party owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The third-party owners' arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the third-party owners' fees and expenses. TEP and the third-party owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015 the third-party owners filed an amended arbitration demand adding claims that TEP has converted the third-party owners' water rights and certain emission reduction payments and that TEP is improperly dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity.
In October 2015 the arbitration panel granted TEP's motion for interim relief, ordering the owner trustees and co-trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the third-party owners' motion for interim relief, which had requested that TEP be enjoined from dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling the third-party owners' entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015. The arbitration hearing is scheduled for July 2016.
In November 2015 TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming owner trustee and co-trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015 the owner trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order.
As at December 31, 2015, TEP billed the third-party owners approximately US$23 million for their pro-rata share of Springerville Unit 1 expenses and US$4 million for their pro-rata share of capital expenditures, none of which had been paid as of February 17, 2016.
TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the claims, the Company cannot determine estimates of the range of loss, if any, at this time and, accordingly, no amount has been accrued in the consolidated financial statements. TEP intends to vigorously defend itself against the claims asserted by the third-party owners and to vigorously pursue the claims it has asserted against the third-party owners.
TEP and the third-party owners have agreed to stay these litigation matters relating to Springerville Unit 1 in furtherance of settlement negotiations. However, there is no assurance that a settlement will be reached or that the litigation will not continue.
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$43 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The mine reclamation liability recorded as at December 31, 2015 was US$25 million (December 31, 2014 - US$22 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.
Central Hudson
Site Investigation and Remediation Program
Central Hudson and its predecessors owned and operated MGPs to serve their customers' heating and lighting needs. These plants manufactured gas from coal and oil beginning in the mid to late 1800s, with all sites ceasing operations by the 1950s. This process produced certain by-products that may pose risks to human health and the environment.
The New York State 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 December 31, 2015, an obligation of US$92 million (December 31, 2014 - US$105 million) was recognized in respect of site investigation and remediation and, based upon cost model analysis completed in 2014, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$169 million.
Central Hudson has notified its insurers and intends to seek reimbursement from insurers for remediation, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return. In the three-year rate order issued by the PSC in June 2015, Central Hudson's authorization to defer all site investigation and remediation costs was reaffirmed and extended through June 2018.
Asbestos Litigation
Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,350 asbestos cases have been raised, 1,167 remained pending as at December 31, 2015. Of the cases no longer pending against Central Hudson, 2,027 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which include FortisBC Electric, use of a road on top of the dam. The Government of British Columbia estimates its damages and the damages of the homeowners, on whose behalf it is claiming, to be approximately $15 million. While FortisBC Electric has notified its insurers, it has been advised by the Government of British Columbia that a response to the claim is not required at this time. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FHI
In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
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. The significant related-party transactions for the years ended December 31, 2015 and 2014 are discussed below.
Upon completion of the Waneta Expansion in early April 2015, FortisBC Electric commenced purchasing capacity from the Waneta Expansion under terms of the 40-year WECA, as approved by the BCUC. Power purchased by FortisBC Electric from the Waneta Expansion in 2015 totalled approximately $30 million. In addition, the Waneta Expansion pays FortisBC Electric for management services associated with the generating station, which totalled approximately $7 million in 2015.
From time to time, the Corporation provides short-term financing to certain of its subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements, bearing interest at rates that approximate the Corporation's cost of short-term borrowing. In addition, the Corporation provided long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation's cost of long-term debt. The majority of this long-term financing was repaid in 2015 as a result of the sale of commercial real estate and hotel assets. As at December 31, 2015, inter-segment loans outstanding totalled $48 million (December 31, 2014 - $402 million) and total interest charged in 2015 was $17 million (2014 - $27 million).
SELECTED ANNUAL FINANCIAL INFORMATION
The following table sets forth the annual financial information for the years ended December 31, 2015, 2014 and 2013.
| Selected Annual Financial Information | |||
| Years Ended December 31 | |||
| ($ millions, except per share amounts) | 2015 | 2014 | 2013 |
| Revenue | 6,727 | 5,401 | 4,047 |
| Net earnings | 840 | 390 | 420 |
| Net earnings attributable to common equity shareholders | 728 | 317 | 353 |
| Basic earnings per common share | 2.61 | 1.41 | 1.74 |
| Diluted earnings per common share | 2.59 | 1.40 | 1.73 |
| Total assets | 28,804 | 26,233 | 17,908 |
| Long-term debt (excluding current portion) | 10,784 | 9,911 | 6,424 |
| Preference shares | 1,820 | 1,820 | 1,229 |
| Common shareholders' equity | 8,060 | 6,871 | 4,772 |
| Dividends declared per common share | 1.43 | 1.30 | 1.25 |
| Dividends declared per First Preference Share, Series C (1) | - | - | 0.4862 |
| Dividends declared per First Preference Share, Series E | 1.2250 | 1.2250 | 1.2250 |
| Dividends declared per First Preference Share, Series F | 1.2250 | 1.2250 | 1.2250 |
| Dividends declared per First Preference Share, Series G (2) | 0.9708 | 0.9708 | 1.1416 |
| Dividends declared per First Preference Share, Series H (3) | 0.7344 | 1.0625 | 1.0625 |
| Dividends declared per First Preference Share, Series I (3) | 0.3637 | - | - |
| Dividends declared per First Preference Share, Series J | 1.1875 | 1.1875 | 1.1875 |
| Dividends declared per First Preference Share, Series K (4) | 1.0000 | 1.0000 | 0.6233 |
| Dividends declared per First Preference Share, Series M (5) | 1.0250 | 0.4613 | - |
| (1) | In July 2013 the Corporation redeemed all of the issued and outstanding First Preference Shares, Series C. |
| (2) | The annual fixed dividend per share for the First Preference Shares, Series G was reset from $1.3125 to $0.9708 for the five-year period from and including September 1, 2013 to but excluding September 1, 2018. |
| (3) | On June 1, 2015, 2,975,154 of the 10,000,000 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I. The annual fixed dividend per share for the First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from and including June 1, 2015 to but excluding June 1, 2020. The First Preference Shares, Series I are entitled to receive floating rate cumulative dividends, which rate will be reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus 1.45%. |
| (4) | The Fixed Rate Reset First Preference Shares, Series K were issued in July 2013 and are entitled to receive cumulative dividends in the amount of $1.0000 per share per annum for the first six years. |
| (5) | The Fixed Rate Reset First Preference Shares, Series M were issued in September 2014 and are entitled to receive cumulative dividends in the amount of $1.0250 per share per annum for the first five years. |
2015/2014: Revenue increased $1,326 million, or 24.6%, from 2014 and net earnings attributable to common equity shareholders were $728 million, or $2.61 per common share, compared to $317 million, or $1.41 per common share, in 2014. For a discussion of the reasons for the changes in revenue, net earnings attributable to common equity shareholders, and earnings per common share, refer to the "Consolidated Results of Operations" and "Summary Financial Highlights" sections of this MD&A.
The growth in total assets reflects favourable foreign exchange on the translation of US dollar-denominated assets and continued investment in energy infrastructure, driven by capital spending at the regulated utilities, partially offset by the sale of commercial real estate and hotel assets in 2015. The increase in long-term debt was primarily due to the issuance of long-term debt at the Corporation's regulated utilities, largely to finance energy infrastructure investment, and the impact of foreign exchange on the translation of US dollar-denominated long-term debt. The increase was partially offset by regularly scheduled debt repayments and net repayments under committed credit facilities, mainly at the Corporation, using net proceeds from the sale of commercial real estate and hotel assets.
2014/2013: Revenue increased $1,354 million, or 33.5%, from 2013. The increase in revenue was driven by the acquisition of UNS Energy in August 2014 and Central Hudson in June 2013. A higher commodity cost of natural gas charged to customers at FortisBC Energy, an increase in the base component of rates at most of the regulated utilities and higher electricity sales also contributed to the increase in revenue.
Net earnings attributable to common equity shareholders were $317 million in 2014 compared to $353 million in 2013. Results for both years were impacted by non-recurring items, largely associated with the acquisition of UNS Energy in 2014 and Central Hudson in 2013. Earnings for 2014 were reduced by $39 million due to acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy, compared to $34 million associated with the acquisition of Central Hudson in 2013. Interest expense of $51 million after tax, including the make-whole payment, associated with convertible debentures issued to finance a portion of the acquisition of UNS Energy was recognized in 2014. In addition, earnings for 2013 were favourably impacted by an income tax recovery of $23 million due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends, an extraordinary gain of $20 million related to the settlement of expropriation matters associated with the Exploits River Hydro Partnership, and the release of income tax provisions of approximately $7 million. An $8 million foreign exchange gain was recognized in 2014 compared to $6 million in 2013. Earnings for 2014 included $5 million associated with Griffith to the date of sale, and earnings for 2013 were reduced by $5 million associated with Griffith.
Excluding the above-noted impacts, net earnings attributable to common equity shareholders for 2014 were $394 million, an increase of $58 million from $336 million for 2013. The increase was driven by $60 million of earnings contribution at UNS Energy from the date of acquisition and the first full year of earnings contribution from Central Hudson, which was acquired in June 2013. Rate base growth and an increase in the number of customers at FortisAlberta and electricity sales growth at Caribbean Regulated Electric Utilities also contributed to the increase. The increase was partially offset by lower earnings at FortisBC Electric, primarily due to the impact of lower-than-expected finance charges in 2013 and higher Corporate and Other expenses. The increase in Corporate and Other expenses was primarily due to higher finance charges, largely due to the acquisitions of UNS Energy and Central Hudson, and higher operating expenses, partially offset by a higher income tax recovery and interest income.
The growth in total assets reflects the Corporation's acquisition of UNS Energy in August 2014 and continued investment in energy infrastructure, driven by capital spending at the regulated utilities in western Canada and the continued construction of the Waneta Expansion. The increase in long-term debt was primarily due to the financing of the acquisition of UNS Energy, including debt assumed on acquisition, and the financing of energy infrastructure investments.
Basic earnings per common share were $1.41 in 2014 compared to $1.74 in 2013. Excluding the above-noted non-recurring items in 2014 and 2013, basic earnings per common share were $1.75 for 2014, an increase of $0.09 from $1.66 for 2013. The increase was driven by accretion associated with the acquisition of UNS Energy.
FOURTH QUARTER RESULTS
The following tables set forth unaudited financial information for the fourth quarters ended December 31, 2015 and 2014.
| Summary of Gas Volumes and Electricity and Energy Sales | |||||
| Fourth Quarters Ended December 31 (Unaudited) | 2015 | 2014 | Variance | ||
| Regulated Electric & Gas Utilities - United States | |||||
| UNS Energy - Electricity Sales (GWh) | 3,562 | 3,583 | (21 | ) | |
| UNS Energy - Gas Volumes (PJ) | 4 | 4 | - | ||
| Central Hudson - Electricity Sales (GWh) | 1,160 | 1,176 | (16 | ) | |
| Central Hudson - Gas Volumes (PJ) | 5 | 5 | - | ||
| Regulated Gas Utility - Canadian | |||||
| FortisBC Energy (PJ) | 62 | 59 | 3 | ||
| Regulated Electric Utilities - Canadian | |||||
| FortisAlberta (GWh) | 4,188 | 4,446 | (258 | ) | |
| FortisBC Electric (GWh) | 836 | 846 | (10 | ) | |
| Eastern Canadian (GWh) | 2,189 | 2,203 | (14 | ) | |
| Regulated Electric Utilities - Caribbean (GWh) | 201 | 187 | 14 | ||
| Non-Regulated - Fortis Generation (GWh) | 122 | 109 | 13 | ||
Gas Volumes
The increase in gas volumes at FortisBC Energy was mainly due to higher gas volumes for transportation customers due to certain customers switching to natural gas compared to alternative fuel sources.
Electricity and Energy Sales
The decrease in energy deliveries at FortisAlberta was primarily due to lower average consumption by oil and gas customers as a result of low commodity prices for oil and gas. At most of the other regulated electric utilities, the decrease was mainly due to lower average consumption due to warmer temperatures, which reduced heating requirements. At the Regulated Electric Utilities - Caribbean, the impact of warmer temperatures increased electricity sales, due to higher air conditioning load. The overall decrease was partially offset by higher non-regulated energy sales, driven by the Waneta Expansion.
| Segmented Revenue and Net Earnings Attributable to Common Equity Shareholders | |||||||||||||
| Fourth Quarters Ended December 31 (Unaudited) | Revenue | Net Earnings | |||||||||||
| ($ millions, except per share amounts) | 2015 | 2014 | Variance | 2015 | 2014 | Variance | |||||||
| Regulated Electric & Gas Utilities - United States | |||||||||||||
| UNS Energy | 482 | 435 | 47 | 26 | 23 | 3 | |||||||
| Central Hudson | 202 | 186 | 16 | 15 | 4 | 11 | |||||||
| 684 | 621 | 63 | 41 | 27 | 14 | ||||||||
| Regulated Gas Utility - Canadian | |||||||||||||
| FortisBC Energy | 411 | 432 | (21 | ) | 65 | 49 | 16 | ||||||
| Regulated Electric Utilities - Canadian | |||||||||||||
| FortisAlberta | 140 | 132 | 8 | 29 | 25 | 4 | |||||||
| FortisBC Electric | 99 | 90 | 9 | 8 | 12 | (4 | ) | ||||||
| Eastern Canadian Electric Utilities | 273 | 266 | 7 | 15 | 14 | 1 | |||||||
| 512 | 488 | 24 | 52 | 51 | 1 | ||||||||
| Regulated Electric Utilities - Caribbean | 82 | 84 | (2 | ) | 9 | 6 | 3 | ||||||
| Non-Regulated - Fortis Generation | 30 | 8 | 22 | 11 | 4 | 7 | |||||||
| Non-Regulated - Non-Utility | 6 | 62 | (56 | ) | 1 | 7 | (6 | ) | |||||
| Corporate and Other | 2 | 7 | (5 | ) | (44 | ) | (31 | ) | (13 | ) | |||
| Inter-Segment Eliminations | (19 | ) | (9 | ) | (10 | ) | - | - | - | ||||
| Total | 1,708 | 1,693 | 15 | 135 | 113 | 22 | |||||||
| Basic Earnings per Common Share ($) | 0.48 | 0.44 | 0.04 | ||||||||||
Revenue
The increase in revenue was mainly due to favourable foreign exchange associated with the translation of US dollar-denominated revenue, contribution from the Waneta Expansion, and an increase in base electricity rates at the Canadian Regulated Electric Utilities. The increase was partially offset by the flow through in customer rates of lower energy supply costs at FortisBC Energy, Central Hudson and Caribbean Regulated Electric Utilities, and a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets.
Earnings
The increase in earnings was primarily due to: (i) favourable foreign exchange impacts; (ii) an increase in base electricity rates at Central Hudson effective July 1, 2015, combined with the impact of storm restoration and other non-recurring expenses recognized in the fourth quarter of 2014; (iii) earnings contribution of approximately $6 million from the Waneta Expansion; (iv) rate base growth associated with capital expenditures and growth in the number of customers at FortisAlberta; and (v) a higher AFUDC at FortisBC Energy, partially offset by higher operating expenses. The timing of regulatory deferral mechanisms had a favourable impact on FortisBC Energy's earnings for the quarter and an unfavourable impact on FortisBC Electric. The increase in earnings was partially offset by lower earnings contribution due to the sale of commercial real estate and hotel assets and higher Corporate and Other expenses. Corporate and Other expenses included $7 million in acquisition-related expenses in the fourth quarter of 2015 and in the fourth quarter of 2014 included $4 million in interest expense associated with the convertible debentures and a $3 million foreign exchange gain. Excluding these items, the increase in Corporate and Other expenses was mainly due to a lower income tax recovery and lower related-party interest income.
| Summary of Consolidated Cash Flows | |||||||
| Fourth Quarters Ended December 31 (Unaudited) | |||||||
| ($ millions) | 2015 | 2014 | Variance | ||||
| Cash, Beginning of Period | 347 | 458 | (111 | ) | |||
| Cash Provided by (Used in): | |||||||
| Operating Activities | 397 | 334 | 63 | ||||
| Investing Activities | (234 | ) | (829 | ) | 595 | ||
| Financing Activities | (280 | ) | 257 | (537 | ) | ||
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | 12 | 10 | 2 | ||||
| Cash, End of Period | 242 | 230 | 12 | ||||
Cash flow from operating activities was $63 million higher quarter over quarter. The increase was primarily due to higher cash earnings at the Corporation's regulated utilities.
Cash used in investing activities was $595 million lower quarter over quarter. The decrease was mainly due to lower capital expenditures at the regulated utilities, largely due to UNS Energy's purchase of Gila River Unit 3 generation station in December 2014 for approximately $252 million (US$219 million), and proceeds received from the sale of hotel assets in October 2015 for $365 million.
Cash provided by financing activities was $537 million lower quarter over quarter. The decrease was primarily due to the repayment of credit facility borrowings in the fourth quarter of 2015 using proceeds from the sale of hotel assets. In addition, lower proceeds from long-term debt and lower credit facility borrowings were partially offset by lower repayments of long-term debt. In the fourth quarter of 2014, proceeds from the second installment of the convertible debentures were received, which were used to repay acquisition credit facilities used initially to finance a portion of the acquisition of UNS Energy.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended March 31, 2014 through December 31, 2015. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results | Net Earnings | |||
| (Unaudited) | Attributable to | Earnings per Common | ||
| Common Equity | Share | |||
| Revenue | Shareholders | Basic | Diluted | |
| Quarter Ended | ($ millions) | ($ millions) | ($) | ($) |
| December 31, 2015 | 1,708 | 135 | 0.48 | 0.48 |
| September 30, 2015 | 1,566 | 151 | 0.54 | 0.54 |
| June 30, 2015 | 1,538 | 244 | 0.88 | 0.87 |
| March 31, 2015 | 1,915 | 198 | 0.72 | 0.71 |
| December 31, 2014 | 1,693 | 113 | 0.44 | 0.43 |
| September 30, 2014 | 1,197 | 14 | 0.06 | 0.06 |
| June 30, 2014 | 1,056 | 47 | 0.22 | 0.22 |
| March 31, 2014 | 1,455 | 143 | 0.67 | 0.66 |
The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions and associated acquisition-related expenses, and the impact of sale transactions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand in different regions, 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 FortisBC Energy are realized in the first and fourth quarters. Earnings for UNS Energy's electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
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. A discussion of the variances in financial results for the fourth quarter of 2015 and the fourth quarter of 2014 is provided in the "Fourth Quarter Results" section of this MD&A.
September 2015/September 2014: Net earnings attributable to common equity shareholders were $151 million, or $0.54 per common share, for the third quarter of 2015 compared to earnings of $14 million, or $0.06 per common share, for the third quarter of 2014. Earnings for the third quarter of 2015 were favourably impacted by a $5 million gain on the sale of non-regulated generation assets in Ontario and a $5 million positive adjustment associated with the sale of hotel assets, and were reduced by a $9 million loss on the settlement of expropriation matters related to the Corporation's investment in Belize Electricity. Earnings for the third quarter of 2014 were reduced by a total of $58 million due to acquisition-related expenses associated with UNS Energy. Excluding these items, the increase in earnings was driven by contribution of $97 million at UNS Energy compared to $37 million for the third quarter of 2014. Earnings contribution of $5 million from the Waneta Expansion also contributed to the increase. Performance was also driven by the Corporation's other regulated utilities, including rate base growth associated with capital expenditures and customer growth at FortisAlberta; improved performance at Central Hudson; and favourable foreign exchange associated with US dollar-denominated earnings. Earnings at FortisBC Energy and FortisBC Electric were impacted by the timing of regulatory deferral mechanisms; however, FortisBC Energy's earnings were favourably impacted by lower operating expenses and higher AFUDC. The increase was partially offset by higher preference share dividends and finance charges in the Corporate and Other segment, largely associated with the acquisition of UNS Energy.
June 2015/June 2014: Net earnings attributable to common equity shareholders were $244 million, or $0.88 per common share, for the second quarter of 2015 compared to earnings of $47 million, or $0.22 per common share, for the second quarter of 2014. The increase was driven by a net gain of $123 million on the sale of commercial real estate, hotel and non-regulated generation assets. The increase was also due to earnings contribution of $52 million at UNS Energy and $12 million from the Waneta Expansion, representing the Corporation's 51% controlling ownership. Performance was also driven by the Corporation's regulated utilities, including rate base growth associated with capital expenditures, customer growth and a decrease in depreciation and amortization at FortisAlberta; increases at FortisBC Electric, largely due to timing of quarterly earnings compared to the same periods last year, resulting from the impact of regulatory deferral mechanisms; and improved performance at Central Hudson. The increase was partially offset by a $5 million decrease in earnings at FortisBC Energy due to the timing of regulatory flow-through deferral amounts, and higher preference share dividends and finance charges in the Corporate and Other segment associated with the acquisition of UNS Energy.
March 2015/March 2014: Net earnings attributable to common equity shareholders were $198 million, or $0.72 per common share, for the first quarter of 2015 compared to earnings of $143 million, or $0.67 per common share, for the first quarter of 2014. The increase in earnings was driven by the Corporation's regulated utilities. UNS Energy contributed earnings of $20 million in the first quarter of 2015. FortisAlberta's earnings were favourably impacted by higher capital tracker revenue, including approximately $10 million associated with 2013 and 2014, and customer growth. Earnings at FortisBC Energy and FortisBC Electric were $9 million and $5 million, respectively, higher quarter over quarter, largely due to timing of quarterly earnings compared to the same periods last year resulting from the impact of regulatory deferral mechanisms. Central Hudson and Eastern Canadian Regulated Electric Utilities also reported improved performance. The increase in earnings at the regulated utilities was partially offset by lower earnings at the Corporation's non-regulated subsidiaries, largely due to decreased production in Belize as a result of lower rainfall, costs at Fortis Properties associated with the strategic review, and approximately $5 million earnings contribution in the first quarter of 2014 from Griffith to the date of sale. Corporate and Other expenses were lower quarter over quarter, due to approximately $11 million in after-tax interest expense associated with the convertible debentures in the first quarter of 2014 and a higher foreign exchange gain, partially offset by higher preference share dividends and finance charges associated with the acquisition of UNS Energy.
MANAGEMENT'S EVALUATON OF DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
Disclosure Controls and Procedures: The President and Chief Executive Officer ("CEO") and the Executive Vice President, Chief Financial Officer ("CFO") of Fortis, together with management, have established and maintain disclosure controls and procedures for the Corporation in order to provide reasonable assurance that material information relating to the Corporation is made known to them in a timely manner, particularly during the period in which the annual filings are being prepared. The CEO and CFO of Fortis, together with management, have evaluated the design and operating effectiveness of the Corporation's disclosure controls and procedures as of December 31, 2015 and, based on that evaluation, have concluded that these controls and procedures are effective in providing such reasonable assurance.
Internal Controls over Financial Reporting: The CEO and CFO of Fortis, together with management, are also responsible for establishing and maintaining internal controls over financial reporting ("ICFR") within the Corporation in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with US GAAP. The CEO and CFO of Fortis, together with management, have evaluated the design and operating effectiveness of the Corporation's ICFR as of December 31, 2015 and, based on that evaluation, have concluded that the controls are effective in providing such reasonable assurance. During the fourth quarter of 2015, there was no change in the Corporation's ICFR that has materially affected, or is reasonably likely to materially affect, the Corporation's ICFR.
SUBSEQUENT EVENT
On February 9, 2016, Fortis and ITC entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 Fortis common shares per ITC common share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
ITC is the largest independent pure-play electric transmission company in the United States. ITC owns and operates high-voltage transmission facilities in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, serving a combined peak load exceeding 26,000 MW along approximately 15,600 miles of transmission line. In addition, ITC is a public utility and independent transmission owner in Wisconsin. ITC's tariff rates are regulated by FERC, which has been one of the most consistently supportive utility regulators in North America providing reasonable returns and equity ratios. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, those of FERC, the Committee on Foreign Investment in the United States, and the United States Federal Trade Commission/Department of Justice under the Hart-Scott Rodino Antitrust Improvement Act. The closing of the Acquisition is expected to occur in late 2016.
The pending Acquisition is in alignment with the Corporation's business model and acquisition strategy, and is expected to provide approximately 5% accretion to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses and assuming a stable currency exchange environment. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the Acquisition.
The financing of the Acquisition has been structured to allow Fortis to maintain investment-grade credit ratings and is consistent with the Corporation's existing capital structure. Financing of the cash portion of the Acquisition will be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of up to 19.9% of ITC to one or more infrastructure-focused minority investors. In addition, Fortis has 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. These non-revolving term credit facilities are repayable in full on the first anniversary of their advance, and although syndication is not required, Fortis expects that these bridge facilities will be syndicated.
Upon completion of the Acquisition, ITC will become a subsidiary of Fortis and approximately 27% of the common shares of Fortis will be held by ITC shareholders. In connection with the Acquisition, Fortis will become a registrant with the SEC and will apply to list its common shares on the New York Stock Exchange and will continue to have its shares listed on the TSX.
OUTLOOK
Fortis is focused on closing the acquisition of ITC by the end of 2016. The Acquisition is in alignment with the Corporation's business model and acquisition strategy, and is expected to provide approximately 5% accretion to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses and assuming a stable currency exchange environment. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.
Substantially all of Fortis' assets are low-risk, regulated utilities and long-term contracted energy infrastructure. No single regulatory jurisdiction comprises more than one-third of total assets. Over the five-year period through 2020, excluding the acquisition of ITC, the Corporation's highly executable capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to almost $21 billion in 2020 and produce a five-year compound annual growth rate in rate base of approximately 5%.
On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the acquisition of ITC. Following the Acquisition, Fortis will be one of the top 15 North American public utilities ranked by enterprise value, with an estimated enterprise value of $42 billion. Additionally, ITC's midyear rate base, including construction work in progress, is expected to increase at a compound annual growth rate of approximately 7.5% through 2018, based on ITC's planned capital expenditure program.
Fortis continues to target 6% average annual dividend growth through 2020. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of assets and record of operational excellence. The pending acquisition of ITC further supports this dividend guidance.
Fortis expects long-term sustainable growth in rate base, assets and earnings resulting from strategic acquisitions and investment in its existing utility operations. The Corporation is also committed to identifying and executing on opportunities for incremental rate base and earnings growth through additional investments in existing service territories, and in new franchise areas.
OUTSTANDING SHARE DATA
As at February 16, 2016, the Corporation had issued and outstanding 281.9 million common shares; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options and First Preference Shares, Series E were converted as at February 16, 2016 is as follows.
| Conversion of Securities into Common Shares | |
| As at February 16, 2016 (Unaudited) | Number of |
| Common Shares | |
| Security | (millions) |
| Stock Options | 4.9 |
| First Preference Shares, Series E | 5.8 |
| Total | 10.7 |
Additional information, including the Fortis 2015 Annual Information Form, Management Information Circular and Audited Consolidated Financial Statements, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Audited Consolidated Financial Statements
As at and for the years ended December 31, 2015 and 2014
Prepared in accordance with accounting principles generally accepted in the United States
Management's Report
The accompanying Annual Consolidated Financial Statements of Fortis Inc. have been prepared by management, who is responsible for the integrity of the information presented including the amounts that must, of necessity, be based on estimates and informed judgments. These Annual Consolidated Financial Statements were prepared in accordance with accounting principles generally accepted in the United States.
In meeting its responsibility for the reliability and integrity of the Annual Consolidated Financial Statements, management has developed and maintains a system of accounting and reporting which provides for the necessary internal controls to ensure transactions are properly authorized and recorded, assets are safeguarded and liabilities are recognized. The systems of the Corporation and its subsidiaries focus on the need for training of qualified and professional staff and the effective communication of management guidelines and policies. The effectiveness of the internal controls of Fortis Inc. is evaluated on an ongoing basis.
The Board of Directors oversees management's responsibilities for financial reporting through an Audit Committee which is composed entirely of outside independent directors. The Audit Committee oversees the external audit of the Corporation's Annual Consolidated Financial Statements and the accounting and financial reporting and disclosure processes and policies of the Corporation. The Audit Committee meets with management, the shareholders' auditors and the internal auditor to discuss the results of the external audit, the adequacy of the internal accounting controls and the quality and integrity of financial reporting. The Corporation's Annual Consolidated Financial Statements are reviewed by the Audit Committee with each of management and the shareholders' auditors before the statements are recommended to the Board of Directors for approval. The shareholders' auditors have full and free access to the Audit Committee. The Audit Committee has the duty to review the adoption of, and changes in, accounting principles and practices which have a material effect on the Corporation's Annual Consolidated Financial Statements and to review and report to the Board of Directors on policies relating to the accounting and financial reporting and disclosure processes.
The Audit Committee has the duty to review financial reports requiring Board of Directors' approval prior to the submission to securities commissions or other regulatory authorities, to assess and review management judgments material to reported financial information and to review shareholders' auditors' independence and auditors' fees. The 2015 Annual Consolidated Financial Statements were reviewed by the Audit Committee and, on their recommendation, were approved by the Board of Directors of Fortis Inc. Ernst & Young LLP, independent auditors appointed by the shareholders of Fortis Inc. upon recommendation of the Audit Committee, have performed an audit of the 2015 Annual Consolidated Financial Statements and their report follows.
Barry V. Perry
President and Chief Executive Officer, Fortis Inc.
Karl W. Smith
Executive Vice President, Chief Financial Officer, Fortis Inc.
St. John's, Canada
Independent Auditors' Report
To the Shareholders of Fortis Inc.
We have audited the accompanying consolidated financial statements of Fortis Inc., which comprise the consolidated balance sheets as at December 31, 2015 and 2014, and the consolidated statements of earnings, comprehensive income, cash flows and changes in equity for the years then ended, and a summary of significant accounting policies and other explanatory information.
Management's responsibility for the consolidated financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Fortis Inc. as at December 31, 2015 and 2014, and its financial performance and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States.
St. John's, Canada
February 17, 2016
Ernst & Young LLP
Chartered Professional Accountants
| Fortis Inc. | ||||
| Consolidated Balance Sheets | ||||
| As at December 31 | ||||
| (in millions of Canadian dollars) | ||||
| 2015 | 2014 | |||
| (Note 36) | ||||
| ASSETS | ||||
| Current assets | ||||
| Cash and cash equivalents | $ | 242 | $ | 230 |
| Accounts receivable and other current assets (Note 6) | 964 | 900 | ||
| Prepaid expenses | 68 | 59 | ||
| Inventories (Note 7) | 337 | 321 | ||
| Regulatory assets (Note 8) | 246 | 277 | ||
| 1,857 | 1,787 | |||
| Other assets (Note 9) | 352 | 272 | ||
| Regulatory assets (Note 8) | 2,286 | 2,138 | ||
| Utility capital assets (Note 10) | 19,595 | 17,179 | ||
| Non-utility capital assets (Note 11) | - | 664 | ||
| Intangible assets (Note 12) | 541 | 461 | ||
| Goodwill (Note 13) | 4,173 | 3,732 | ||
| $ | 28,804 | $ | 26,233 | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
| Current liabilities | ||||
| Short-term borrowings (Note 32) | $ | 511 | $ | 330 |
| Accounts payable and other current liabilities (Note 14) | 1,419 | 1,440 | ||
| Regulatory liabilities (Note 8) | 298 | 173 | ||
| Current installments of long-term debt (Note 15) | 384 | 525 | ||
| Current installments of capital lease and finance obligations (Note 16) | 26 | 208 | ||
| 2,638 | 2,676 | |||
| Other liabilities (Note 17) | 1,152 | 1,141 | ||
| Regulatory liabilities (Note 8) | 1,340 | 1,272 | ||
| Deferred income taxes (Note 26) | 2,050 | 1,626 | ||
| Long-term debt (Note 15) | 10,784 | 9,911 | ||
| Capital lease and finance obligations (Note 16) | 487 | 495 | ||
| 18,451 | 17,121 | |||
| Shareholders' equity | ||||
| Common shares (1) (Note 18) | 5,867 | 5,667 | ||
| Preference shares (Note 20) | 1,820 | 1,820 | ||
| Additional paid-in capital | 14 | 15 | ||
| Accumulated other comprehensive income (Note 21) | 791 | 129 | ||
| Retained earnings | 1,388 | 1,060 | ||
| 9,880 | 8,691 | |||
| Non-controlling interests (Note 22) | 473 | 421 | ||
| 10,353 | 9,112 | |||
| $ | 28,804 | $ | 26,233 | |
| (1) | No par value. Unlimited authorized shares; 281.6 million and 276.0 million issued and outstanding as at December 31, 2015 and 2014, respectively |
| Approved on Behalf of the Board | ||||
| Commitments (Note 33) | ||||
| Contingencies (Note 34) | David G. Norris, Director | Peter E. Case, Director | ||
| See accompanying Notes to Consolidated Financial Statements | ||||
| Fortis Inc. | ||||||
| Consolidated Statements of Earnings | ||||||
| For the years ended December 31 | ||||||
| (in millions of Canadian dollars, except per share amounts) | ||||||
| 2015 | 2014 | |||||
| Revenue | $ | 6,727 | $ | 5,401 | ||
| Expenses | ||||||
| Energy supply costs | 2,561 | 2,197 | ||||
| Operating | 1,864 | 1,493 | ||||
| Depreciation and amortization | 873 | 688 | ||||
| 5,298 | 4,378 | |||||
| Operating income | 1,429 | 1,023 | ||||
| Other income (expenses), net (Note 24) | 187 | (25 | ) | |||
| Finance charges (Note 25) | 553 | 547 | ||||
| Earnings before income taxes and discontinued operations | 1,063 | 451 | ||||
| Income tax expense (Note 26) | 223 | 66 | ||||
| Earnings from continuing operations | 840 | 385 | ||||
| Earnings from discontinued operations, net of tax (Note 28) | - | 5 | ||||
| Net earnings | $ | 840 | $ | 390 | ||
| Net earnings attributable to: | ||||||
| Non-controlling interests | $ | 35 | $ | 11 | ||
| Preference equity shareholders | 77 | 62 | ||||
| Common equity shareholders | 728 | 317 | ||||
| $ | 840 | $ | 390 | |||
| Earnings per common share from continuing operations (Note 19) | ||||||
| Basic | $ | 2.61 | $ | 1.39 | ||
| Diluted | $ | 2.59 | $ | 1.38 | ||
| Earnings per common share (Note 19) | ||||||
| Basic | $ | 2.61 | $ | 1.41 | ||
| Diluted | $ | 2.59 | $ | 1.40 | ||
| See accompanying Notes to Consolidated Financial Statements | ||||||
| Fortis Inc. | |||||||
| Consolidated Statements of Comprehensive Income | |||||||
| For the years ended December 31 | |||||||
| (in millions of Canadian dollars) | |||||||
| 2015 | 2014 | ||||||
| Net earnings | $ | 840 | $ | 390 | |||
| Other comprehensive income (loss) | |||||||
| Unrealized foreign currency translation gains, net of hedging activities and tax (Note 21) | 660 | 204 | |||||
| Reclassification to earnings of foreign currency translation loss on disposal of investment in foreign operations, net of tax (Note 21) | 2 | - | |||||
| Net change in fair value of cash flow hedges, net of tax (Notes 21 and 31) | 1 | 1 | |||||
| Reclassification to earnings of net losses on derivative instruments discontinued as cash flow hedges, net of tax (Note 21) | - | 1 | |||||
| Unrealized loss on available-for-sale investment, net of tax (Notes 9, 21 and 31) | (2 | ) | - | ||||
| Unrealized employee future benefits gains (losses), net of tax (Notes 21 and 27) | 1 | (5 | ) | ||||
| 662 | 201 | ||||||
| Comprehensive income | $ | 1,502 | $ | 591 | |||
| Comprehensive income attributable to: | |||||||
| Non-controlling interests | $ | 35 | $ | 11 | |||
| Preference equity shareholders | 77 | 62 | |||||
| Common equity shareholders | 1,390 | 518 | |||||
| $ | 1,502 | $ | 591 | ||||
| See accompanying Notes to Consolidated Financial Statements | |||||||
| Fortis Inc. | |||||||
| Consolidated Statements of Cash Flows | |||||||
| For the years ended December 31 | |||||||
| (in millions of Canadian dollars) | |||||||
| 2015 | 2014 | ||||||
| Operating activities | |||||||
| Net earnings | $ | 840 | $ | 390 | |||
| Adjustments to reconcile net earnings to net cash provided by operating activities: | |||||||
| Depreciation - capital assets | 785 | 597 | |||||
| Amortization - intangible assets | 64 | 60 | |||||
| Amortization - other | 24 | 31 | |||||
| Deferred income tax expense (Note 26) | 164 | 23 | |||||
| Accrued employee future benefits | (19 | ) | 25 | ||||
| Equity component of allowance for funds used during construction (Note 24) | (23 | ) | (11 | ) | |||
| Gain on sale of non-utility capital assets (Note 24) | (131 | ) | - | ||||
| Gain on sale of non-regulated generation assets (Note 24) | (62 | ) | - | ||||
| Other | 79 | 71 | |||||
| Change in long-term regulatory assets and liabilities | (89 | ) | (80 | ) | |||
| Change in non-cash operating working capital (Note 30) | 41 | (124 | ) | ||||
| 1,673 | 982 | ||||||
| Investing activities | |||||||
| Change in other assets and other liabilities | (36 | ) | (4 | ) | |||
| Capital expenditures - utility capital assets | (2,122 | ) | (1,617 | ) | |||
| Capital expenditures - non-utility capital assets | (9 | ) | (39 | ) | |||
| Capital expenditures - intangible assets | (112 | ) | (69 | ) | |||
| Contributions in aid of construction | 59 | 69 | |||||
| Purchase of assets held for sale (Notes 6 and 16) | (32 | ) | - | ||||
| Proceeds on sale of assets (Notes 16 and 28) | 922 | 109 | |||||
| Business acquisitions, net of cash acquired (Notes 9 and 29) | (38 | ) | (2,648 | ) | |||
| (1,368 | ) | (4,199 | ) | ||||
| Financing activities | |||||||
| Change in short-term borrowings | 148 | 167 | |||||
| Proceeds from convertible debentures, net of issue costs (Note 18) | - | 1,725 | |||||
| Proceeds from long-term debt, net of issue costs (Note 15) | 1,002 | 1,193 | |||||
| Repayments of long-term debt and capital lease and finance obligations | (602 | ) | (743 | ) | |||
| Net (repayments) borrowings under committed credit facilities | (622 | ) | 610 | ||||
| Advances from non-controlling interests | 20 | 38 | |||||
| Issue of common shares, net of costs and dividends reinvested (Note 18) | 40 | 51 | |||||
| Issue of preference shares, net of costs (Note 20) | - | 586 | |||||
| Dividends | |||||||
| Common shares, net of dividends reinvested | (232 | ) | (194 | ) | |||
| Preference shares | (77 | ) | (62 | ) | |||
| Subsidiary dividends paid to non-controlling interests | (23 | ) | (10 | ) | |||
| (346 | ) | 3,361 | |||||
| Effect of exchange rate changes on cash and cash equivalents | 53 | 14 | |||||
| Change in cash and cash equivalents | 12 | 158 | |||||
| Cash and cash equivalents, beginning of year | 230 | 72 | |||||
| Cash and cash equivalents, end of year | $ | 242 | $ | 230 | |||
| Supplementary Information to Consolidated Statements of Cash Flows (Note 30) | |||||||
| See accompanying Notes to Consolidated Financial Statements | |||||||
| Fortis Inc. |
| Consolidated Statements of Changes in Equity |
| For the years ended December 31, 2015 and 2014 |
| (in millions of Canadian dollars) |
| Accumulated | |||||||||||||||||||||
| Additional | Other | Non- | |||||||||||||||||||
| Common | Preference | Paid-in | Comprehensive | Retained | Controlling | Total | |||||||||||||||
| Shares | Shares | Capital | Income (Loss) | Earnings | Interests | Equity | |||||||||||||||
| (Note 18 | ) | (Note 20 | ) | (Note 21 | ) | (Note 22 | ) | ||||||||||||||
| As at January 1, 2015 | $ | 5,667 | $ | 1,820 | $ | 15 | $ | 129 | $ | 1,060 | $ | 421 | $ | 9,112 | |||||||
| Net earnings | - | - | - | - | 805 | 35 | 840 | ||||||||||||||
| Other comprehensive income | - | - | - | 662 | - | - | 662 | ||||||||||||||
| Common share issues | 200 | - | (4 | ) | - | - | - | 196 | |||||||||||||
| Stock-based compensation | - | - | 3 | - | - | - | 3 | ||||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 20 | 20 | ||||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | 20 | 20 | ||||||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (23 | ) | (23 | ) | ||||||||||||
| Dividends declared on common shares ($1.43 per share) | - | - | - | - | (400 | ) | - | (400 | ) | ||||||||||||
| Dividends declared on preference shares | - | - | - | - | (77 | ) | - | (77 | ) | ||||||||||||
| As at December 31, 2015 | $ | 5,867 | $ | 1,820 | $ | 14 | $ | 791 | $ | 1,388 | $ | 473 | $ | 10,353 | |||||||
| As at January 1, 2014 | $ | 3,783 | $ | 1,229 | $ | 17 | $ | (72 | ) | $ | 1,044 | $ | 375 | $ | 6,376 | ||||||
| Net earnings | - | - | - | - | 379 | 11 | 390 | ||||||||||||||
| Other comprehensive income | - | - | - | 201 | - | - | 201 | ||||||||||||||
| Preference share issue | - | 591 | - | - | - | - | 591 | ||||||||||||||
| Common share issues | 1,884 | - | (5 | ) | - | - | - | 1,879 | |||||||||||||
| Stock-based compensation | - | - | 3 | - | - | - | 3 | ||||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 38 | 38 | ||||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | 7 | 7 | ||||||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (10 | ) | (10 | ) | ||||||||||||
| Dividends declared on common shares ($1.30 per share) | - | - | - | - | (301 | ) | - | (301 | ) | ||||||||||||
| Dividends declared on preference shares | - | - | - | - | (62 | ) | - | (62 | ) | ||||||||||||
| As at December 31, 2014 | $ | 5,667 | $ | 1,820 | $ | 15 | $ | 129 | $ | 1,060 | $ | 421 | $ | 9,112 | |||||||
| See accompanying Notes to Consolidated Financial Statements |
| FORTIS INC. |
| NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |
| For the years ended December 31, 2015 and 2014 |
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation assets, which are 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 summary describes the operations included in each of the Corporation's reportable segments.
REGULATED UTILITIES
The Corporation's interests in regulated electric and gas utilities are as follows.
Regulated Electric & Gas Utilities - United States
a. UNS Energy: Primarily comprised of Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), (collectively, the "UNS Utilities"), acquired by Fortis in August 2014 (Note 29).
TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility. TEP generates, transmits and distributes electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP also sells wholesale electricity to other entities in the western United States.
UNS Electric is a vertically integrated regulated electric utility, which generates, transmits and distributes electricity to retail customers in Arizona's Mohave and Santa Cruz counties.
TEP and UNS Electric currently own generation resources with an aggregate capacity of 2,799 megawatts ("MW"), including 54 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2015, approximately 43% of the generating capacity was fuelled by coal.
UNS Gas is a regulated gas distribution utility, serving retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.
b. Central Hudson: Central Hudson Gas & Electric Corporation ("Central Hudson") is a regulated transmission and distribution ("T&D") utility, serving eight counties of New York State's Mid-Hudson River Valley. The Company owns gas-fired and hydroelectric generating capacity totalling 64 MW.
Regulated Gas Utility - Canadian
FortisBC Energy: Primarily includes FortisBC Energy Inc. ("FortisBC Energy" or "FEI") and, prior to December 31, 2014, FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"). On December 31, 2014, FEI, FEVI and FEWI were amalgamated and FEI is the resulting Company (Note 2). FEI is the largest distributor of natural gas in British Columbia, serving more than 135 communities. Major areas served by the Company are the Lower Mainland, Vancouver Island and Whistler regions of British Columbia. FEI provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through FEI's Southern Crossing pipeline, from Alberta.
Regulated Electric Utilities - Canadian
- FortisAlberta: FortisAlberta Inc. ("FortisAlberta") owns and operates the electricity distribution system in a substantial portion of southern and central Alberta. The Company does not own or operate generation or transmission assets and is not involved in the direct sale of electricity.
- FortisBC Electric: Includes FortisBC Inc., an integrated electric utility operating in the southern interior of British Columbia. FortisBC Inc. owns four hydroelectric generating facilities with a combined capacity of 225 MW. Also included in the FortisBC Electric segment are the operating, maintenance and management services relating to the 493-MW Waneta hydroelectric generating facility owned by Teck Metals Ltd. and BC Hydro; the 335-MW Waneta Expansion hydroelectric generating facility ("Waneta Expansion"), owned by Fortis and Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT"); the 149-MW Brilliant hydroelectric plant and the 120-MW Brilliant hydroelectric expansion plant, both owned by CPC/CBT; and the 185-MW Arrow Lakes hydroelectric plant owned by CPC/CBT.
- Eastern Canadian: Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited ("Maritime Electric") and FortisOntario Inc. ("FortisOntario"). Newfoundland Power is an integrated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Newfoundland Power has an installed generating capacity of 139 MW, of which 97 MW is hydroelectric generation. Maritime Electric is an integrated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI"). Maritime Electric also maintains on-Island generating facilities with a combined capacity of 150 MW. FortisOntario provides integrated electric utility service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. FortisOntario's operations are primarily comprised of Canadian Niagara Power Inc. ("Canadian Niagara Power"), Cornwall Street Railway, Light and Power Company, Limited ("Cornwall Electric") and Algoma Power Inc. ("Algoma Power").
Regulated Electric Utilities - Caribbean
The Regulated Electric Utilities - Caribbean segment includes the Corporation's approximate 60% controlling ownership interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities") (December 31, 2014 - 60%), Fortis Turks and Caicos, and the Corporation's 33% equity investment in Belize Electricity Limited ("Belize Electricity") (Note 9). Caribbean Utilities is an integrated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. The Company has an installed diesel-powered generating capacity of 132 MW. Caribbean Utilities is a public company traded on the Toronto Stock Exchange ("TSX") (TSX:CUP.U). Fortis Turks and Caicos is comprised of two integrated electric utilities that provide electricity to certain islands in Turks and Caicos. The utilities have a combined diesel-powered generating capacity of 82 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.
NON-REGULATED - FORTIS GENERATION
Fortis Generation is primarily comprised of long-term contracted generation assets in British Columbia and Belize. Generating assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion. Construction of the Waneta Expansion was completed in April 2015 and the output is sold to BC Hydro and FortisBC Electric under 40-year contracts. The Corporation's 51% controlling ownership interest in the Waneta Expansion is conducted through the Waneta Expansion Limited Partnership ("Waneta Partnership"), with CPC/CBT holding the remaining 49% interest.
Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW. All of the output of these facilities is sold to Belize Electricity under 50-year power purchase agreements ("PPAs") expiring in 2055 and 2060. The hydroelectric generation operations in Belize are conducted through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL") under a franchise agreement with the Government of Belize ("GOB").
As at December 31, 2015, the 16-MW run-of-river Walden hydroelectric generating facility ("Walden") has been classified as held for sale (Note 6).
In June 2015 and July 2015 the Corporation sold its non-regulated generation assets in Upstate New York and Ontario, respectively (Notes 24 and 28).
NON-REGULATED - NON-UTILITY
The Non-Utility segment previously included Fortis Properties Corporation ("Fortis Properties") and Griffith Energy Services, Inc. ("Griffith"). Fortis Properties completed the sale of its commercial real estate assets in June 2015 and its hotel assets in October 2015, and Griffith was sold in March 2014 (Note 28).
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. ("CH Energy Group") 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.
2. NATURE OF REGULATION
The Corporation's regulated utilities are primarily 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.
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 (Note 8).
The nature of regulation at the Corporation's utilities is as follows.
UNS Energy
The UNS Utilities are regulated by the Arizona Corporation Commission ("ACC") and certain activities are subject to regulation by the U.S. Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States). The UNS Utilities operate under COS regulation as administered by the ACC, which provides for the use of a historical test year in the establishment of retail electric and gas rates. Retail electric and gas rates are set to provide the utilities with an opportunity to recover their COS and earn a reasonable rate of return on rate base, including an adjustment for the fair value of rate base as required under the laws of the State of Arizona.
TEP's allowed ROE is set at 10.0% on a capital structure of 43.5% common equity, effective from July 1, 2013. UNS Electric's allowed ROE is set at 9.50% on a capital structure of 52.6% common equity, effective from January 1, 2014. UNS Gas' allowed ROE is set at 9.75% on a capital structure of 50.8% common equity, effective from May 1, 2012.
Central Hudson
Central Hudson is regulated by the New York State Public Service Commission ("PSC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). The Company is also subject to regulation by the North American Electric Reliability Corporation. Central Hudson operates under COS regulation as administered by the PSC with the use of a future test year in the establishment of rates.
Central Hudson began operating under a three-year rate order issued by the PSC effective July 1, 2010 with an allowed ROE set at 10.0% on a deemed capital structure of 48% common equity. As approved by the PSC in June 2013, the original three-year rate order was extended for two years, through June 30, 2015, as part of the regulatory approval of the acquisition of Central Hudson by Fortis. In June 2015 the PSC issued a rate order for the Company covering a three-year period, with new electricity and natural gas delivery rates effective July 1, 2015. The new rate order reflects an allowed ROE of 9.0% and a 48% common equity component of capital structure.
Effective July 1, 2013, Central Hudson was also subject to an earnings sharing mechanism, whereby the Company and customers share equally earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis points above the allowed ROE, and share 10%/90% (Company/customers) earnings in excess of 50 basis points above the allowed ROE. In the new rate order effective July 1, 2015, the earnings sharing mechanism was continued, whereby the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Earnings in excess of 100 basis points above the allowed ROE are shared primarily with the customer.
FortisBC Energy and FortisBC Electric
FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC") pursuant to the Utilities Commission Act (British Columbia). The Companies primarily operate under COS regulation and, from time to time, PBR mechanisms for establishing customer rates.
In the first stage of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia, FEI was designated as the benchmark utility and a BCUC decision established that the allowed ROE for the benchmark utility would be set at 8.75% on a 38.5% common equity component of capital structure, both effective January 1, 2013 through December 31, 2015. In March 2014 the BCUC issued its decision on the second stage of the GCOC Proceeding, setting the common equity component of capital structure for FEVI and FEWI at 41.5%, and reaffirming the common equity component of capital structure for FortisBC Electric at 40%, all effective January 1, 2013. The resulting allowed ROEs for FEVI, FEWI and FortisBC Electric were 9.25%, 9.50% and 9.15%, respectively, also effective January 1, 2013. Effective January 1, 2015, following the amalgamation of FEI, FEVI and FEWI, the ROE and common equity component of capital structure for the amalgamated FEI, was set to equal the benchmark utility, at 8.75% and 38.5%, respectively.
FEI and FortisBC Electric are subject to Multi-Year PBR Plans for 2014 through 2019. The PBR Plans, as approved by the BCUC, incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of 1.1% for FEI and 1.03% for FortisBC Electric each year. The approved PBR Plans also include a 50%/50% sharing of variances from the formula-driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FEI and FortisBC Electric maintain service levels. It also sets out the requirements for an annual review process which will provide a forum for discussion between the utilities and interested parties regarding current performance and future activities.
FortisAlberta
FortisAlberta is regulated by the Alberta Utilities Commission ("AUC") pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). Effective January 1, 2013, the AUC prescribed that distribution utilities in Alberta, including FortisAlberta, move to PBR for a five-year term. Under PBR, each year the prescribed formula is applied to the preceding year's distribution rates, with 2012 used as the going-in distribution rates.
The PBR plan includes mechanisms for the recovery or settlement of items determined to flow through directly to customers ("Y factor") and the recovery of costs related to capital expenditures that are not being recovered through the formula ("K factor" or "capital tracker"). The AUC also approved a Z factor, a PBR re-opener and an ROE efficiency carry-over mechanism. The Z factor permits an application for recovery of costs related to significant unforeseen events. The PBR re-opener permits an application to re-open and review the PBR plan to address specific problems with the design or operation of the PBR plan. The use of the Z factor and PBR re-opener mechanisms is associated with certain thresholds. The ROE efficiency carry-over mechanism provides an efficiency incentive by permitting a utility to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term.
The funding of capital expenditures during the PBR term is a material aspect of the PBR plan for FortisAlberta. The PBR plan provides a capital tracker mechanism to fund the recovery of costs associated with certain qualifying capital expenditures. In March 2015 the AUC issued its decision related to FortisAlberta's 2013, 2014 and 2015 Capital Tracker Applications. The decision: (i) indicated that the majority of the Company's applied for capital trackers met the established criteria and were, therefore, approved for collection from customers; (ii) approved FortisAlberta's accounting test to determine qualifying K factor amounts; and (iii) confirmed certain inputs to be used in the accounting test, including the conclusion that the weighted average cost of capital be based on actual debt rates and the allowed ROE and capital structure approved in the GCOC Proceeding.
In September 2015 the AUC approved FortisAlberta's compliance filing related to the 2015 Capital Tracker Decision, substantially as filed. Capital tracker revenue of $17 million was approved for 2013 on an actual basis and capital tracker revenue of $42 million and $62 million was approved on a forecast basis for 2014 and 2015, respectively. FortisAlberta collected $15 million, $29 million and $62 million in 2013, 2014 and 2015, respectively, related to capital tracker expenditures.
FortisAlberta recognized capital tracker revenue of approximately $59 million in 2015, of which $9 million was related to updates to the 2013 and 2014 capital tracker approved amounts. The capital tracker revenue for 2015 of approximately $50 million incorporates an update for related 2015 capital tracker expenditures as compared to the approved forecast reflected in current rates. This resulted in a deferral of $12 million of 2015 capital tracker revenue as a regulatory liability.
In March 2015 the AUC issued its decision on the GCOC Proceeding in Alberta. The GCOC Proceeding set FortisAlberta's allowed ROE for 2013 through 2015 at 8.30%, down from the interim allowed ROE of 8.75%, and set the common equity component of capital structure at 40%, down from 41%. The AUC also determined that it would not re-establish a formula-based approach to setting the allowed ROE at this time. Instead, the allowed ROE of 8.30% and common equity component of capital structure of 40% will remain in effect on an interim basis for 2016 and beyond. For regulated utilities in Alberta under PBR mechanisms, including FortisAlberta, the impact of the changes to the allowed ROE and common equity component of capital structure resulting from the GCOC Proceeding applies to the portion of rate base that is funded by capital tracker revenue only. For assets not being funded by capital tracker revenue, no revenue adjustment is required for the change in the allowed ROE and common equity component of capital structure, from that set in an earlier GCOC decision.
Eastern Canadian Electric Utilities
Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") under the Public Utilities Act (Newfoundland and Labrador). Newfoundland Power operates under COS regulation with the use of a future test year in the establishment of rates. The PUB has set the allowed ROE at 8.80% and the common equity component of capital structure at 45% for 2013 through 2015.
Maritime Electric is regulated by the Island Regulatory and Appeals Commission ("IRAC") under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI), the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and the Electric Power (Energy Accord Continuation) Amendment Act (PEI) ("Accord Continuation Act"), which covers the period March 1, 2013 to February 29, 2016. Maritime Electric operates under COS regulation with the use of a future test year for the establishment of rates. IRAC set the allowed ROE at 9.75% on a targeted minimum capital structure of 40% common equity for 2014 and 2015.
In Ontario, Canadian Niagara Power, Algoma Power and Cornwall Electric operate under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario), as administered by the Ontario Energy Board ("OEB"). Canadian Niagara Power and Algoma Power operate under COS regulation and earnings are regulated on the basis of rate of return on rate base, plus a recovery of allowable distribution costs. In non-rebasing years, customer electricity distribution rates are set using inflationary factors less an efficiency target under the Fourth-Generation Incentive Regulation Mechanism as prescribed by the OEB. Algoma Power is also subject to the use and implementation of the Rural and Remote Rate Protection ("RRRP") Program. The RRRP Program is calculated as the deficiency between the approved revenue requirement from the OEB and current customer electricity distribution rates, adjusted for the average rate increase across the province of Ontario. Canadian Niagara Power and Algoma Power use a future test year in the establishment of rates. Canadian Niagara Power's allowed ROE for distribution assets was set at 8.93% for 2014 and 2015 and the allowed ROE for transmission assets was set at 8.93% for 2014 and 9.30% for 2015, both on a deemed capital structure of 40% common equity. Algoma Power's allowed ROE was set at 9.85% for 2014 and 9.30% for 2015 on a deemed capital structure of 40% common equity. Cornwall Electric is subject to a rate-setting mechanism under a 35-year Franchise Agreement with the City of Cornwall expiring in 2033 and, therefore, is exempt from many aspects of the above Acts. The rate-setting mechanism is based on a price cap with commodity cost flow through. The base revenue requirement is adjusted annually for inflation, load growth and customer growth.
Regulated Electric Utilities - Caribbean
Caribbean Utilities operates under T&D and generation licences from the Government of the Cayman Islands. The exclusive T&D licence is for an initial period of 20 years, expiring April 2028, with a provision for automatic renewal. In November 2014 a new non-exclusive generation licence was issued for a term of 25 years, expiring in November 2039. The licences detail the role of the Electricity Regulatory Authority, which oversees all licences, establishes and enforces licence standards, reviews the rate-cap adjustment mechanism ("RCAM"), and annually approves capital expenditures. The licences contain the provision for an RCAM based on published consumer price indices. Caribbean Utilities' targeted allowed ROA for 2015 was in the range of 7.25% to 9.25%, compared to a range of 7.00% to 9.00% for 2014.
Fortis Turks and Caicos operates under two 50-year licences expiring in 2036 and 2037. Among other matters, the licences describe how electricity rates are set by the Government of the Turks and Caicos Islands, using a historical test year, in order to provide the utilities with an allowed ROA of between 15.0% and 17.5% (the "Allowable Operating Profit"). The Allowable Operating Profit is based on a calculated rate base including interest on the amounts by which actual operating profits fall short of the Allowable Operating Profits on a cumulative basis (the "Cumulative Shortfall"). Annual submissions are made to the Government of the Turks and Caicos Islands calculating the amount of the Allowable Operating Profit and the Cumulative Shortfall. The submissions for 2015 calculated the Allowable Operating Profit to be $51 million (US$40 million) and the Cumulative Shortfall as at December 31, 2015 to be $274 million (US$198 million). The recovery of the Cumulative Shortfall is, however, dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed under the licences as a result of the inability, due to economic and political factors, to increase base electricity rates associated with significant capital investment in recent years.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP"), which for regulated utilities include specific accounting guidance for regulated operations, as outlined in Note 2, and the following summary of significant accounting policies.
All amounts presented are in Canadian dollars unless otherwise stated.
Basis of Presentation
The consolidated financial statements reflect the Corporation's investments in its subsidiaries on a consolidated basis, with the equity method used for entities in which Fortis has significant influence, but not control, and proportionate consolidation for generation and transmission assets that are jointly owned with non-affiliated entities. All material intercompany transactions have been eliminated in the consolidated financial statements.
An evaluation of subsequent events through to February 17, 2016, the date these consolidated financial statements were approved by the Board of Directors of Fortis ("Board of Directors"), was completed to determine whether the circumstances warranted recognition and disclosure of events or transactions in the consolidated financial statements as at December 31, 2015 (Note 35).
Cash and Cash Equivalents
Cash and cash equivalents include cash and short-term deposits with initial maturities of three months or less from the date of deposit.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects management's best estimate of uncollectible accounts receivable balances. Fortis and each of its subsidiaries maintain an allowance for doubtful accounts that is estimated based on a variety of factors including accounts receivable aging, historical experience and other currently available information, including events such as customer bankruptcy and economic conditions. Interest is charged on accounts receivable balances that have been outstanding for more than 21 to 30 days. Accounts receivable are written-off in the period in which the receivable is deemed uncollectible.
Inventories
Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and market value, unless evidence indicates that the weighted average cost, even in excess of market, will be recovered in future customer rates.
Regulatory Assets and Liabilities
Regulatory assets and liabilities arise as a result of the rate-setting process at the Corporation's regulated utilities. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process.
All amounts deferred as regulatory assets and liabilities are subject to regulatory approval. As such, the regulatory authorities could alter the amounts subject to deferral, at which time the change would be reflected in the consolidated financial statements. Certain remaining recovery and settlement periods are those expected by management and the actual recovery or settlement periods could differ based on regulatory approval.
Investments
Portfolio investments are accounted for on the cost basis. Declines in value considered to be other than temporary are recorded in the period in which such determinations are made. Investments in which the Corporation exercises significant influence are accounted for on the equity basis. The Corporation reviews its investments on an annual basis for potential impairment in investment value. Should an impairment be identified, it will be recognized in the period in which such impairment is identified.
Available-for-Sale Assets
The Corporation's assets designated as available-for-sale are measured at fair value based on quoted market prices. Unrealized gains or losses resulting from changes in fair value are recognized in accumulated other comprehensive income and are reclassified to earnings when the assets are sold.
Utility Capital Assets
Utility capital assets are recorded at cost less accumulated depreciation. Contributions in aid of construction represent amounts contributed by customers and governments for the cost of utility capital assets. These contributions are recorded as a reduction in the cost of utility capital assets and are being amortized annually by an amount equal to the charge for depreciation provided on the related assets.
Each of UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, Newfoundland Power and Maritime Electric accrue estimated non-asset retirement obligations ("AROs") removal costs in depreciation, as required by their respective regulator, with the amount provided for in depreciation recorded as a long-term regulatory liability (Note 8 (xiv)). Actual non-ARO removal costs are recorded against the regulatory liability when incurred. As permitted by the regulator, FortisBC Electric records actual non-ARO removal costs, net of salvage proceeds, against accumulated depreciation as incurred. FortisOntario, Fortis Turks and Caicos and Waneta Expansion recognize non-ARO removal costs, net of salvage proceeds, in earnings in the period incurred. Caribbean Utilities recognizes non-ARO removal costs in utility capital assets.
Utility capital assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of utility capital assets, any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation by UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos, as required by their respective regulator, with no gain or loss, if any, recognized in earnings. It is expected that any gains or losses charged to accumulated depreciation will be reflected in future depreciation expense when they are refunded or collected in customer electricity and gas rates. At FortisOntario, as required by its regulator, and the Waneta Partnership, any remaining net book value, net of salvage proceeds, upon retirement or disposal of utility capital assets is recognized immediately in earnings.
As required by their respective regulator, UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos, capitalize overhead costs that are not directly attributable to specific utility capital assets but relate to the overall capital expenditure program. The methodology for calculating and allocating capitalized general overhead costs to utility capital assets is established by the respective regulator.
As required by their respective regulator, UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric and Caribbean Utilities include in the cost of utility capital assets both a debt and an equity component of the allowance for funds used during construction ("AFUDC"). The debt component of AFUDC is reported as a reduction of finance charges (Note 25) and the equity component of AFUDC is reported as other income (Note 24). Both components of AFUDC are charged to earnings through depreciation expense over the estimated service lives of the applicable utility capital assets. AFUDC is calculated in a manner as prescribed by the respective regulator.
At FortisAlberta, the cost of utility capital assets also includes Alberta Electric System Operator ("AESO") contributions, which are investments required by FortisAlberta to partially fund the construction of transmission facilities.
As approved by the regulator, FortisBC Energy has reduced the amounts reported for utility capital assets by the amount of government loans received in connection with the construction and operation of the Vancouver Island natural gas pipeline. As the loans are repaid and replaced with non-government loans, FortisBC Energy increases both utility capital assets and long-term debt (Note 15).
Utility capital assets include inventories held for the development, construction and betterment of other utility capital assets, with the exception of UNS Energy. As required by its regulator, UNS Energy recognizes inventories held for the development and construction of other utility capital assets in inventories until consumed. When put into service, the inventories are reclassified to utility capital assets (Note 7).
Maintenance and repairs of utility capital assets are charged to earnings in the period incurred, while replacements and betterments which extend the useful lives are capitalized.
Utility capital assets are depreciated using the straight-line method based on the estimated service lives of the utility capital assets. Depreciation rates for regulated utility capital assets are approved by the respective regulator. Depreciation rates for 2015 ranged from 1.3% to 43.2% (2014 - 1.3% to 43.2%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, for 2015 was 3.1% (2014 - 3.2%).
The service life ranges and weighted average remaining service life of the Corporation's distribution, transmission, generation and other assets as at December 31 were as follows:
| 2015 | 2014 | ||||
| Weighted | Weighted | ||||
| Average | Average | ||||
| Service Life | Remaining | Service Life | Remaining | ||
| (Years) | Ranges | Service Life | Ranges | Service Life | |
| Distribution | |||||
| Electric | 5-80 | 30 | 5-80 | 28 | |
| Gas | 4-95 | 33 | 4-85 | 31 | |
| Transmission | |||||
| Electric | 20-80 | 29 | 20-70 | 27 | |
| Gas | 7-80 | 36 | 4-71 | 38 | |
| Generation | 5-85 | 27 | 4-75 | 24 | |
| Other | 3-70 | 8 | 3-70 | 8 | |
Non-Utility Capital Assets
In 2015 the Corporation sold its commercial real estate and hotel assets, which included office buildings, shopping malls, hotels, land, construction in progress, and related equipment and tenant inducements (Note 28). Non-utility capital assets were recorded at cost less accumulated depreciation, where applicable, using the straight-line method of depreciation.
Maintenance and repairs were charged to earnings in the period incurred, while replacements and betterments which extended the useful lives were capitalized.
Leases
Leases that transfer to the Corporation substantially all of the risks and benefits incidental to ownership of the leased item are capitalized at the present value of the minimum lease payments. Included as capital leases are any arrangements that qualify as leases by conveying the right to use a specific asset.
Capital leases are depreciated over the lease term, except where ownership of the asset is transferred at the end of the lease term, in which case capital leases are depreciated over the estimated service life of the underlying asset. Where the regulator has approved recovery of the arrangements as operating leases for rate-setting purposes that would otherwise qualify as capital leases for financial reporting purposes, the timing of the expense recognition related to the lease is modified to conform with the rate-setting process.
Operating lease payments are recognized as an expense in earnings on a straight-line basis over the lease term.
Intangible Assets
Intangible assets are recorded at cost less accumulated amortization. Intangible assets are comprised of computer software costs; land, transmission and water rights; and franchise fees. The cost of intangible assets at the Corporation's regulated subsidiaries includes amounts for AFUDC and allocated overhead, where permitted by the respective regulators. Costs incurred to renew or extend the term of an intangible asset are capitalized and amortized over the new term of the intangible asset.
The useful lives of intangible assets are assessed to be either indefinite or finite. Intangible assets with indefinite useful lives are tested for impairment annually, either individually or at the reporting unit level, if they are held in a regulated utility. Such intangible assets are not amortized. Indefinite-lived intangible assets, not subject to amortization, consist of certain land, transmission and water rights at UNS Energy, FortisBC Energy, FortisBC Electric and the Waneta Partnership. An intangible asset with an indefinite useful life is reviewed annually to determine whether the indefinite life assessment continues to be supportable. If not, the change in the useful life assessment from indefinite to finite is made on a prospective basis.
In testing indefinite-lived intangible assets for impairment, the Corporation has the option, on an annual basis, of performing a qualitative assessment before calculating fair value. If the qualitative factors indicate that fair value is 50% or more likely to be greater than the carrying value, calculation of fair value would not be required.
Impairment testing for indefinite-lived intangible assets is carried out at the reporting unit level at the regulated utilities. A fair rate of return on the indefinite-lived intangible assets is provided through customer electricity and gas rates, as approved by the respective regulatory authority. The net cash flows for regulated enterprises are not asset-specific but are pooled for the entire regulated utility.
Fortis performs the annual impairment test as at October 1. In addition, the Corporation also performs an impairment test if any event occurs or if circumstances change that would indicate that the fair value of the indefinite-lived intangible assets is below its carrying value. No such event or change in circumstances occurred during 2015 or 2014 and there were no impairment provisions required in either year. For its annual testing of impairment for indefinite-lived intangible assets, Fortis uses the approach for the annual testing for goodwill impairment as disclosed in this Note under "Goodwill".
Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets and are assessed for impairment whenever there is an indication that the intangible asset may be impaired. Amortization rates for regulated intangible assets are approved by the respective regulator.
Amortization rates for 2015 ranged from 1.0% to 50.0% (2014 - 1.0% to 50.0%). The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows:
| 2015 | 2014 | |||
| Weighted | Weighted | |||
| Average | Average | |||
| Service Life | Remaining | Service Life | Remaining | |
| (Years) | Ranges | Service Life | Ranges | Service Life |
| Computer software | 3-10 | 4 | 3-10 | 4 |
| Land, transmission and water rights | 30-80 | 37 | 30-75 | 32 |
| Franchise fees and other | 10-104 | 15 | 10-100 | 19 |
Intangible assets are derecognized on disposal or when no future economic benefits are expected from their use. Upon retirement or disposal of intangible assets, any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization by UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, Caribbean Utilities and Fortis Turks and Caicos, as required by their respective regulator, with no gain or loss, if any, recognized in earnings. It is expected that any gains or losses charged to accumulated amortization will be reflected in future amortization costs when they are refunded or collected in customer electricity and gas rates. At FortisOntario, as required by its regulator, and the Waneta Partnership, any remaining net book value, net of salvage proceeds, upon retirement or disposal of intangible assets is recognized immediately in earnings.
Impairment of Long-Lived Assets
The Corporation reviews the valuation of utility capital assets, intangible assets with finite lives and other long-term assets when events or changes in circumstances indicate that the assets' carrying value exceeds the total undiscounted cash flows expected from their use and eventual disposition. An impairment loss, calculated as the difference between the assets' carrying value and their fair value, which is determined using present value techniques, is recognized in earnings in the period in which it is identified. There was no material impact on the consolidated financial statements as a result of regulated long-lived asset or non-regulated generation asset impairments for the years ended December 31, 2015 and 2014. Certain of the Corporation's non-utility hotel assets, all of which were sold in 2015, were subject to an impairment charge as a result of the carrying amount of the assets exceeding their fair value (Note 28).
Asset-impairment testing at the regulated utilities is carried out at the enterprise level to determine if assets are impaired. The recovery of regulated assets' carrying value, including a fair rate of return, is provided through customer electricity and gas rates approved by the respective regulatory authority. The net cash flows for regulated enterprises are not asset-specific but are pooled for the entire regulated utility.
The process for asset-impairment testing differs for non-regulated generation assets compared to regulated utility assets. Since each non-regulated generating facility provides an individual cash flow stream, such an asset is tested individually and impairment is recorded if the future net cash flows are no longer sufficient to recover the carrying value of the generating facility.
Goodwill
Goodwill represents the excess, at the dates of acquisition, of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired and liabilities assumed relating to business acquisitions. Goodwill is carried at initial cost less any write-down for impairment.
Fortis performs an annual internal quantitative assessment for each reporting unit. For those reporting units where: (i) management's assessment of quantitative and qualitative factors indicates that fair value is not 50% or more likely to be greater than carrying value; or (ii) where the excess of estimated fair value over carrying value, as determined by an external consultant as of the date of the immediately preceding impairment test, was not significant, then fair value of the reporting unit will be estimated by an external consultant in the current year. Irrespective of the above-noted approach, a reporting unit to which goodwill has been allocated may have its fair value estimated by an external consultant as at the annual impairment date, as Fortis will, at a minimum, have fair value for each material reporting unit estimated by an external consultant once every five years.
Fortis performs the annual impairment test as at October 1. In addition, the Corporation also performs an impairment test if any event occurs or if circumstances change that would indicate that the fair value of a reporting unit is below its carrying value. No such event or change in circumstances occurred during 2015 or 2014 and no impairment provisions were required in either year.
In calculating goodwill impairment, Fortis determines those reporting units that will have fair value estimated by an external consultant, as described above, and such estimated fair value is then compared to the book value of the applicable reporting units. If the fair value of the reporting unit is less than the book value, a second measurement step is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill, and then comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of the goodwill over the implied fair value is the impairment amount recognized.
The primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections for the reporting units are discounted using an enterprise value approach. Under the enterprise value approach, sustainable cash flow is determined on an after-tax basis, prior to the deduction of interest expense, and is then discounted at the weighted average cost of capital to yield the value of the enterprise. An enterprise value approach does not assess the appropriateness of the reporting unit's existing debt level. The estimated fair value of the reporting unit is then determined by subtracting the fair value of the reporting unit's interest-bearing debt from the enterprise value of the reporting unit. A secondary valuation method, the market approach, may also be performed by an external consultant as a check on the conclusions reached under the income approach. The market approach includes comparing various valuation multiples underlying the discounted cash flow analysis of the applicable reporting units to trading multiples of guideline entities and recent transactions involving guideline entities, recognizing differences in growth expectations, product mix and risks of those guideline entities with the applicable reporting units.
Employee Future Benefits
Defined Benefit and Defined Contribution Pension Plans
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, including retirement allowances and supplemental retirement plans for certain executive employees, and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans for employees. The projected benefit obligation and the value of pension cost associated with the defined benefit pension plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation and expected retirement ages of employees. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected pension payments.
With the exception of FortisBC Energy and Newfoundland Power, pension plan assets are valued at fair value for the purpose of determining pension cost. At FortisBC Energy and Newfoundland Power, pension plan assets are valued using the market-related value for the purpose of determining pension cost, where investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years.
The excess of any cumulative net actuarial gain or loss over 10% of the greater of the projected benefit obligation and the fair value of plan assets (the market-related value of plan assets at FortisBC Energy and Newfoundland Power) at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.
The net funded or unfunded status of defined benefit pension plans, measured as the difference between the fair value of the plan assets and the projected benefit obligation, is recognized on the Corporation's consolidated balance sheet.
With the exception of UNS Energy, FortisAlberta and Maritime Electric, any difference between pension cost recognized under US GAAP and that recovered from customers in current rates for defined benefit pension plans, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment (Note 8 (ii)). As approved by the regulator, the cost of defined benefit pension plans at FortisAlberta is recovered in customer rates based on the cash payments made.
At UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric and FortisOntario, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment (Note 8 (ii)). At Fortis, FHI and Caribbean Utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension plans are recognized in accumulated other comprehensive income.
The costs of the defined contribution pension plans are expensed as incurred.
Other Post-Employment Benefits Plans
UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, FortisBC Electric, Newfoundland Power, Maritime Electric, FortisOntario and the Corporation also offer other post-employment benefits ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The accumulated benefit obligation and the cost associated with OPEB plans are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan performance, salary escalation, expected retirement ages of employees and health care costs. Discount rates reflect market interest rates on high-quality bonds with cash flows that match the timing and amount of expected OPEB payments.
The excess of any cumulative net actuarial gain or loss over 10% of the accumulated benefit obligation and the fair value of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.
The net funded or unfunded status of OPEB plans, measured as the difference between the fair value of the plan assets and the accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheet.
As approved by the regulator, the cost of OPEB plans at FortisAlberta is recovered in customer rates based on the cash payments made.
With the exception of UNS Energy and FortisAlberta, any difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates, which is expected to be recovered from, or refunded to, customers in future rates, is subject to deferral account treatment (Note 8 (ii)).
At FortisAlberta, the difference between the cost of OPEB plans recognized under US GAAP and that recovered from customers in current rates does not meet the criteria for deferral account treatment and, therefore, FortisAlberta recognizes in earnings the cost associated with its OPEB plan as actuarially determined, rather than as approved by the regulator. Unamortized OPEB plan balances at FortisAlberta related to net actuarial gains and losses and past service costs are recognized as a component of other comprehensive income.
Stock-Based Compensation
The Corporation records compensation expense related to stock options granted under its 2002 Stock Option Plan ("2002 Plan"), 2006 Stock Option Plan ("2006 Plan") and 2012 Stock Option Plan ("2012 Plan") (Note 23). Compensation expense is measured at the date of grant using the Black-Scholes fair value option-pricing model and each grant is amortized as a single award evenly over the four-year vesting period of the options granted. The offsetting entry is an increase to additional paid-in capital for an amount equal to the annual compensation expense related to the issuance of stock options. The stock options become exercisable once time vesting requirements have been met. Upon exercise, the proceeds of the options are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock. An exercise of options below the current market price of the Corporation's common shares has a dilutive effect on the Corporation's consolidated capital stock and shareholders' equity. Fortis satisfies stock option exercises by issuing common shares from treasury.
The Corporation also records liabilities associated with its Directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans, all representing cash settled awards, at fair value at each reporting date until settlement. Compensation expense is recognized on a straight-line basis over the vesting period, which, for the PSU and RSU Plans, is over the shorter of three years or the period to retirement eligibility. The fair value of the DSU, PSU and RSU liabilities is based on the five-day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP of the Corporation's common shares as at December 31, 2015 was $37.72 (December 31, 2014 - $38.96). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate.
Foreign Currency Translation
The assets and liabilities of the Corporation's foreign operations, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and BECOL, all of which have a US dollar functional currency, are translated at the exchange rate in effect as at the balance sheet date. The exchange rate in effect as at December 31, 2015 was US$1.00=CAD$1.38 (December 31, 2014 - US$1.00=CAD$1.16). The resulting unrealized translation gains and losses are excluded from the determination of earnings and are recognized in accumulated other comprehensive income until the foreign subsidiary is sold, substantially liquidated or evaluated for impairment in anticipation of disposal. Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate in effect during the reporting period, which was US$1.00=CAD$1.28 for 2015 (2014 - US$1.00=CAD$1.10).
The Corporation's approximate 33% equity investment in Belize Electricity is translated at the exchange rate in effect as at the balance sheet date. The resulting unrealized translation gains and losses are excluded from the determination of earnings and are recognized in accumulated other comprehensive income until the investment is sold, substantially liquidated or evaluated for impairment in anticipation of disposal (Notes 9 and 24).
Foreign exchange translation gains and losses on foreign currency-denominated long-term debt that is designated as an effective hedge of foreign net investments are accumulated as a separate component of shareholders' equity within accumulated other comprehensive income and the current period change is recorded in other comprehensive income.
Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Gains and losses on translation are recognized in earnings.
Derivative Instruments and Hedging Activities
The Corporation and its subsidiaries use various physical and financial derivative instruments to meet forecast load and reserve requirements, to reduce exposure to fluctuations in commodity prices and foreign exchange rates, and to hedge interest rate risk exposure. The Corporation does not hold or issue derivative instruments for trading purposes and generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges. As at December 31, 2015, the Corporation's derivative instruments primarily consisted of electricity swap contracts, gas swap and option contracts, electricity power purchase contracts, gas purchase contract premiums, long-term wholesale trading contracts, and interest rate swaps (Note 31).
All derivative instruments that do not meet the normal purchase or normal sale scope exception are recognized as assets or liabilities on the consolidated balance sheet and are measured at fair value. Changes in fair value are recognized in earnings unless the instruments qualify, and are designated, as an accounting or economic hedge.
Derivative instruments that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized as energy supply costs on the consolidated statements of earnings. Derivative contracts under master netting agreements and collateral positions are presented on a gross basis. The Corporation is required to bifurcate embedded derivatives from their host instruments and account for them as free-standing derivative instruments if they meet specified criteria.
For derivatives designated as hedging contracts, the Corporation's utilities formally assess, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The hedging strategy by transaction type and risk management strategy is formally documented. As at December 31, 2015, the Corporation's hedging relationships primarily consisted of interest rate swaps and US dollar-denominated borrowings.
The Corporation's earnings from, and net investments in, foreign subsidiaries and significant influence investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased a portion of the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The Corporation has designated its corporately issued US dollar long-term debt as a hedge of a portion of the foreign exchange risk related to its foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as hedges are recognized in other comprehensive income and help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which gains and losses are also recognized in other comprehensive income.
For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates, as permitted by the respective regulators. Accordingly, the net unrealized gains and losses associated with changes in fair value of the derivative contracts are recorded as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8 (vii)).
Income Taxes
The Corporation and its subsidiaries follow the asset and liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are more likely than not to be realized. Valuation allowances are recognized against deferred tax assets when it is more likely than not that a portion of, or the entire amount of, the deferred income tax asset will not be realized. Deferred income tax assets and liabilities are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period that the change occurs. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year.
As approved by the respective regulator, UNS Energy, Central Hudson and Maritime Electric recover current and deferred income tax expense in customer rates. As approved by the regulator, FortisAlberta recovers income tax expense in customer rates based only on income taxes that are currently payable. FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario recover income tax expense in customer rates based only on income taxes that are currently payable, except for certain regulatory balances for which deferred income tax expense is recovered from, or refunded to, customers in current rates, as prescribed by the respective regulator. Therefore, with the exception of certain deferred tax balances of FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario, current customer rates do not include the recovery of deferred income taxes related to temporary differences between the tax basis of assets and liabilities and their carrying amounts for regulatory purposes, as these taxes are expected to be collected in customer rates when they become payable. These utilities recognize an offsetting regulatory asset or liability for the amount of deferred income taxes that are expected to be collected from or refunded to customers in rates once income taxes become payable or receivable (Note 8 (i)).
For regulatory reporting purposes, the capital cost allowance pool for certain utility capital assets at FortisAlberta is different from that for legal entity corporate income tax filing purposes. In a future reporting period, yet to be determined, the difference may result in higher income tax expense than that recognized for regulatory rate-setting purposes and collected in customer rates.
Caribbean Utilities and Fortis Turks and Caicos are not subject to income tax as they operate in tax-free jurisdictions. BECOL is not subject to income tax as it was granted tax-exempt status by the GOB for the terms of its 50-year PPAs.
Any difference between the income tax expense recognized under US GAAP and that recovered from customers in current rates that is expected to be recovered from customers in future rates, is subject to deferral account treatment (Note 8 (i)).
The Corporation intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, the Corporation does not provide for deferred income taxes on temporary differences related to investments in foreign subsidiaries. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $565 million as at December 31, 2015 (December, 2014 - $384 million). If such earnings are repatriated, in the form of dividends or otherwise, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical. Canada has entered into Tax Information Exchange Agreements ("TIEAs") with Bermuda, the Cayman Islands and the Turks and Caicos Islands. Consequently, earnings from the Corporation's foreign subsidiaries operating in these regions, subsequent to 2010, can be repatriated to Canada on a tax-free basis and, therefore, are not included in the amount of temporary differences noted above, as no taxes are payable on these earnings. If a TIEA is entered into with Belize, earnings from the Corporation's operations in Belize would also be able to be repatriated to Canada on a tax-free basis. Negotiations between the Government of Canada and the GOB commenced in June 2010.
Tax benefits associated with income tax positions taken, or expected to be taken, in an income tax return are recognized only when the more likely than not recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The difference between a tax position taken, or expected to be taken, and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.
Income tax interest and penalties are expensed as incurred and included in income tax expense. At FortisAlberta, investment tax credits are deducted from the related assets and are recognized as a reduction of income tax expense as the Company becomes taxable for rate-setting purposes.
Sales Taxes
In the course of its operations, the Corporation's subsidiaries collect sales taxes from their customers. When customers are billed, a current liability is recognized for the sales taxes included on customers' bills. The liability is settled when the taxes are remitted to the appropriate government authority. The Corporation's revenue excludes sales taxes.
For regulatory reporting purposes, Central Hudson recognizes tax revenue collected on behalf of applicable government authorities on a gross basis. In 2015 approximately $19 million was included in both revenue and expenses (2014 - $22 million).
Revenue Recognition
Revenue from the sale of electricity and gas by the Corporation's regulated utilities is generally recognized on an accrual basis. Electricity and gas consumption is metered upon delivery to customers and is recognized as revenue using approved rates when consumed. Revenue at the regulated utilities is billed at rates approved by the applicable regulatory authority, and is generally bundled to include service associated with generation and T&D, except at FortisAlberta and FortisOntario. Meters are read periodically and bills are issued to customers based on these readings. At the end of each reporting period, a certain amount of consumed electricity and gas will not have been billed. Electricity and gas that is consumed but not yet billed to customers is estimated and accrued as revenue at each period end, as approved by the regulator. Effective July 1, 2015, Central Hudson is permitted by the regulator to accrue unbilled revenue for electricity consumed at each period end for all its electricity customers. As at December 31, 2014, approximately $15 million (US$13 million) in unbilled revenue at Central Hudson, associated with certain electricity customers, was not accrued, as permitted by the regulator.
In certain circumstances, UNS Energy enters into purchased power and wholesale sales contracts that are not settled with energy. The net sales contracts and power purchase contracts are reflected at the net amount in revenue.
As stipulated by the regulator, FortisAlberta is required to arrange and pay for transmission services with AESO and collect transmission revenue from its customers, which is achieved through invoicing the customers' retailers through FortisAlberta's transmission component of its regulator-approved rates. FortisAlberta is solely a distribution company and, as such, does not operate or provide any transmission or generation services. The Company is a conduit for the flow through of transmission costs to end-use customers, as the transmission provider does not have a direct relationship with these customers. As a result, FortisAlberta reports revenue and expenses related to transmission services on a net basis. The rates collected are based on forecast transmission expenses. FortisAlberta is not subject to any forecast risk with respect to transmission costs, as all differences between actual expenses related to transmission services and actual revenue collected from customers are deferred to be recovered from, or refunded to, customers in future rates (Note 8 (xviii)).
FortisBC Electric has entered into contracts to sell surplus capacity that may be available after it meets its load requirements. This revenue is recognized on an accrual basis at rates established in the sales contract.
All of the Corporation's non-regulated generation operations record revenue on an accrual basis and revenue is recognized on delivery of output at rates fixed under contract or based on observed market prices as stipulated in contractual arrangements.
Non-utility revenue, associated with commercial real estate and hotel assets that were sold in 2015, was recognized when services were provided or products were delivered to customers. Specifically, real estate revenue, derived from leasing retail and office space, was recognized in the month earned at rates in accordance with lease agreements. The leases were primarily of a net nature, with tenants paying basic rent plus a pro rata share of certain defined overhead expenses. Certain retail tenants paid additional rent based on a percentage of the tenants' sales. Expenses recovered from tenants were recorded as revenue on an accrual basis. Base rent and the escalation of lease rates included in long-term leases were recognized in earnings using the straight-line method over the term of the lease.
Asset Retirement Obligations
AROs, including conditional AROs, are recorded as a liability at fair value and are classified as long-term other liabilities, with a corresponding increase to utility capital assets (Note 17). The Corporation recognizes AROs in the periods in which they are incurred if a reasonable estimate of fair value can be determined. The fair value of AROs is based on an estimate of the present value of expected future cash outlays reflecting a range of possible outcomes, discounted at a credit-adjusted risk-free interest rate. AROs are adjusted at the end of each reporting period to reflect the passage of time and any changes in the estimated future cash flows underlying the obligation. Actual costs incurred upon the settlement of AROs are recorded as a reduction in the liabilities. As permitted by the respective regulator, at UNS Energy, Central Hudson and FortisBC Electric, changes in the obligations due to the passage of time are recognized as a regulatory asset using the effective interest method.
The Corporation has AROs associated with hydroelectric generation facilities, interconnection facilities and wholesale energy supply agreements. While each of the foregoing will have legal AROs, including land and environmental remediation and/or removal of assets, the final date and cost of remediation and/or removal of the related assets cannot be reasonably determined at this time. These assets are reasonably expected to operate in perpetuity due to the nature of their operation. The licences, permits, interconnection facilities agreements and wholesale energy supply agreements are reasonably expected to be renewed or extended indefinitely to maintain the integrity of the assets and ensure the continued provision of service to customers. In the event that environmental issues are identified, assets are decommissioned or the applicable licences, permits or agreements are terminated, AROs will be recorded at that time provided the costs can be reasonably estimated.
The Corporation also has AROs associated with the removal of certain electricity distribution system assets from rights-of-way at the end of the life of the system. As it is expected that the system will be in service indefinitely, an estimate of the fair value of asset removal costs cannot be reasonably determined at this time.
The Corporation has determined that AROs may exist regarding the remediation of certain land. Certain leased land contains assets integral to operations and it is reasonably expected that the land-lease agreement will be renewed indefinitely; therefore, an estimate of the fair value of remediation costs cannot be reasonably determined at this time. Certain other land may require environmental remediation but the amount and nature of the remediation is indeterminable at this time. AROs associated with land remediation will be recorded when the timing, nature and amount of costs can be reasonably estimated.
New Accounting Policies
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
Effective January 1, 2015, the Corporation prospectively adopted Accounting Standards Update ("ASU") No. 2014-08 that changes the criteria and disclosures for reporting discontinued operations. As a result, the sale of commercial real estate and hotel assets and the sale of non-regulated generation assets in 2015 did not meet the criteria for discontinued operations (Note 28). The sales are consistent with the Corporation's focus on its core utility business and, therefore, do not represent a strategic shift in operations.
Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved After the Requisite Service Period
Effective January 1, 2015, the Corporation early adopted ASU No. 2014-12 that resolves diversity in practice for employee share-based payments with performance targets that can entitle an employee to benefit from an award regardless of if they are rendering services at the date the performance target is achieved. The adoption of this update was applied prospectively and did not have a material impact on the Corporation's consolidated financial statements.
Simplifying the Presentation of Debt Issuance Costs
Effective October 1, 2015, the Corporation early adopted ASU No. 2015-03 that requires debt issuance costs to be presented on the consolidated balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The adoption of this update was applied retrospectively and resulted in the reclassification of debt issuance costs of approximately $65 million from long-term other assets to long-term debt on the Corporation's consolidated balance sheet as at December 31, 2014 (Note 36). Additionally, the Corporation early adopted ASU No. 2015-15 that clarifies the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements. The update permits an entity to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The adoption of this update was applied retrospectively and did not have a material impact on the Corporation's consolidated financial statements.
Balance Sheet Classification of Deferred Taxes
Effective October 1, 2015, the Corporation early adopted ASU No. 2015-17 that requires deferred tax assets and liabilities to be classified and presented as long term on the consolidated balance sheet. The adoption of this update was applied retrospectively and resulted in the reclassification of current deferred income taxes assets of $158 million, long-term deferred income tax assets of $62 million, and current deferred income tax liabilities of $9 million to long-term deferred income tax liabilities on the consolidated balance sheet as at December 31, 2014. As a result, the Corporation also reclassified current regulatory assets of $18 million, current regulatory liabilities of $19 million, and long-term regulatory liabilities of $91 million to long-term regulatory assets on the consolidated balance sheet as at December 31, 2014, all associated with regulatory deferred income taxes (Note 36).
Use of Accounting Estimates
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 utilities operate often require amounts to be recorded 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.
The Corporation's critical accounting estimates are described above in Note 3 under the headings Regulatory Assets and Liabilities, Utility Capital Assets, Intangible Assets, Goodwill, Employee Future Benefits, Stock-Based Compensation, Income Taxes, Revenue Recognition and Asset Retirement Obligations, and in Notes 8, 23 and 34.
4. FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create ASC Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard completes a joint effort by FASB and the International Accounting Standards Board to improve financial reporting by creating common revenue recognition guidance for US GAAP and International Financial Reporting Standards that clarifies the principles for recognizing revenue and that can be applied consistently across various transactions, industries and capital markets. This standard was originally effective for annual and interim periods beginning after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. ASU No. 2015-14 was issued in August 2015 and the amendments in this update defer the effective date of ASU No. 2014-09 by one year to annual and interim periods beginning after December 15, 2017. Early adoption is permitted as of the original effective date. The majority of the Corporation's revenue is generated from energy sales to customers based on published tariff rates, as approved by the respective regulators, and is expected to be in the scope of ASU No. 2014-09. Fortis has not yet selected a transition method and is assessing the impact that the adoption of this standard will have on its consolidated financial statements and related disclosures. The Corporation plans to have this assessment substantially complete by the end of 2016.
Amendments to the Consolidation Analysis
ASU No. 2015-02 was issued in February 2015 and 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 with regard to 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. This update is effective for annual and interim periods beginning after December 15, 2015 and may be applied using a modified retrospective approach or retrospectively. The adoption of this update is not expected to materially impact the Corporation's consolidated financial statements, however, it is expected to change the Corporation's 51% controlling ownership interest in Waneta Partnership from a voting interest entity to a variable interest entity, resulting in additional note disclosure.
5. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| REGULATED | NON-REGULATED | ||||||||||||||||||
| United States | Canada | ||||||||||||||||||
| Year Ended | Electric & Gas | Gas | Electric | ||||||||||||||||
| December 31, 2015 | UNS | Central | FortisBC | Fortis | FortisBC | Eastern | Caribbean | Fortis | Non- | Corporate | Inter- segment | ||||||||
| ($ millions) | Energy | Hudson | Total | Energy | Alberta | Electric | Canadian | Total | Electric | Generation | Utility | and Other | eliminations | Total | |||||
| Revenue | 2,034 | 880 | 2,914 | 1,295 | 563 | 360 | 1,033 | 3,251 | 321 | 107 | 171 | 24 | (61 | ) | 6,727 | ||||
| Energy supply costs | 820 | 315 | 1,135 | 498 | - | 116 | 673 | 1,287 | 169 | 1 | - | - | (31 | ) | 2,561 | ||||
| Operating expenses | 573 | 381 | 954 | 292 | 183 | 89 | 143 | 707 | 46 | 19 | 124 | 26 | (12 | ) | 1,864 | ||||
| Depreciation and amortization | 242 | 56 | 298 | 190 | 168 | 57 | 82 | 497 | 47 | 18 | 11 | 2 | - | 873 | |||||
| Operating income (loss) | 399 | 128 | 527 | 315 | 212 | 98 | 135 | 760 | 59 | 69 | 36 | (4 | ) | (18 | ) | 1,429 | |||
| Other income (expenses), net | 5 | 8 | 13 | 11 | 3 | - | 2 | 16 | 2 | 56 | 109 | (8 | ) | (1 | ) | 187 | |||
| Finance charges | 98 | 38 | 136 | 134 | 78 | 39 | 56 | 307 | 14 | 3 | 18 | 94 | (19 | ) | 553 | ||||
| Income tax expense (recovery) | 111 | 40 | 151 | 51 | (1 | ) | 9 | 19 | 78 | - | 24 | 13 | (43 | ) | - | 223 | |||
| Net earnings (loss) | 195 | 58 | 253 | 141 | 138 | 50 | 62 | 391 | 47 | 98 | 114 | (63 | ) | - | 840 | ||||
| Non-controlling interests | - | - | - | 1 | - | - | - | 1 | 13 | 21 | - | - | - | 35 | |||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 77 | - | 77 | |||||
| Net earnings (loss) attributable to common equity shareholders | 195 | 58 | 253 | 140 | 138 | 50 | 62 | 390 | 34 | 77 | 114 | (140 | ) | - | 728 | ||||
| Goodwill | 1,912 | 624 | 2,536 | 913 | 227 | 235 | 67 | 1,442 | 195 | - | - | - | - | 4,173 | |||||
| Identifiable assets | 6,977 | 2,601 | 9,578 | 5,116 | 3,592 | 1,872 | 2,219 | 12,799 | 1,084 | 1,025 | - | 352 | (207 | ) | 24,631 | ||||
| Total assets | 8,889 | 3,225 | 12,114 | 6,029 | 3,819 | 2,107 | 2,286 | 14,241 | 1,279 | 1,025 | - | 352 | (207 | ) | 28,804 | ||||
| Gross capital expenditures | 669 | 181 | 850 | 460 | 452 | 103 | 175 | 1,190 | 137 | 38 | 9 | 19 | - | 2,243 | |||||
| Year Ended | |||||||||||||||||||
| December 31, 2014 | |||||||||||||||||||
| ($ millions) | |||||||||||||||||||
| Revenue | 684 | 821 | 1,505 | 1,435 | 518 | 334 | 1,008 | 3,295 | 321 | 38 | 249 | 31 | (38 | ) | 5,401 | ||||
| Energy supply costs | 272 | 345 | 617 | 646 | - | 87 | 653 | 1,386 | 195 | 1 | - | - | (2 | ) | 2,197 | ||||
| Operating expenses | 209 | 337 | 546 | 287 | 176 | 90 | 143 | 696 | 39 | 10 | 172 | 38 | (8 | ) | 1,493 | ||||
| Depreciation and amortization | 80 | 49 | 129 | 190 | 164 | 59 | 79 | 492 | 38 | 5 | 22 | 2 | - | 688 | |||||
| Operating income (loss) | 123 | 90 | 213 | 312 | 178 | 98 | 133 | 721 | 49 | 22 | 55 | (9 | ) | (28 | ) | 1,023 | |||
| Other income (expenses), net | 4 | 6 | 10 | 4 | 3 | 1 | 2 | 10 | 2 | (1 | ) | - | (45 | ) | (1 | ) | (25 | ) | |
| Finance charges | 34 | 35 | 69 | 139 | 79 | 41 | 56 | 315 | 14 | - | 24 | 154 | (29 | ) | 547 | ||||
| Income tax expense (recovery) | 33 | 24 | 57 | 49 | (1 | ) | 12 | 19 | 79 | - | 1 | 8 | (79 | ) | - | 66 | |||
| Net earnings (loss) from continuing operations | 60 | 37 | 97 | 128 | 103 | 46 | 60 | 337 | 37 | 20 | 23 | (129 | ) | - | 385 | ||||
| Earnings from discontinued operations, net of tax | - | - | - | - | - | - | - | - | - | - | 5 | - | - | 5 | |||||
| Net earnings (loss) | 60 | 37 | 97 | 128 | 103 | 46 | 60 | 337 | 37 | 20 | 28 | (129 | ) | - | 390 | ||||
| Non-controlling interests | - | - | - | 1 | - | - | - | 1 | 10 | - | - | - | - | 11 | |||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 62 | - | 62 | |||||
| Net earnings (loss) attributable to common equity shareholders | 60 | 37 | 97 | 127 | 103 | 46 | 60 | 336 | 27 | 20 | 28 | (191 | ) | - | 317 | ||||
| Goodwill | 1,603 | 523 | 2,126 | 913 | 227 | 235 | 67 | 1,442 | 164 | - | - | - | - | 3,732 | |||||
| Identifiable assets | 5,648 | 2,123 | 7,771 | 4,846 | 3,234 | 1,803 | 2,163 | 12,046 | 924 | 961 | 696 | 543 | (440 | ) | 22,501 | ||||
| Total assets | 7,251 | 2,646 | 9,897 | 5,759 | 3,461 | 2,038 | 2,230 | 13,488 | 1,088 | 961 | 696 | 543 | (440 | ) | 26,233 | ||||
| Gross capital expenditures | 444 | 126 | 570 | 332 | 348 | 92 | 166 | 938 | 71 | 102 | 38 | 6 | - | 1,725 | |||||
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 during the years ended December 31 were as follows.
| Significant Related Party Inter-Segment Transactions | |||||
| (in millions) | 2015 | 2014 | |||
| Sales from Fortis Generation to Regulated Electric Utilities - Canadian | $ | 31 | $ | 2 | |
| Revenue from Regulated Electric Utilities - Canadian to Fortis Generation | 7 | - | |||
| Sales from Regulated Electric Utilities - Canadian to Non-Utility | 4 | 6 | |||
| Inter-segment finance charges on lending from: | |||||
| Fortis Generation to Eastern Canadian Electric Utilities | 1 | 1 | |||
| Corporate to Regulated Electric Utilities - Caribbean | - | 5 | |||
| Corporate to Non-Utility | 17 | 22 | |||
| The significant related party inter-segment asset balances as at December 31 were as follows. | |||||
| Significant Related Party Inter-Segment Assets | |||||
| (in millions) | 2015 | 2014 | |||
| Inter-segment borrowings from: | |||||
| Fortis Generation to Eastern Canadian Electric Utilities | $ | 20 | $ | 20 | |
| Corporate to Regulated Electric Utilities - Canadian | 48 | - | |||
| Corporate to Non-Utility | - | 402 | |||
| Other inter-segment assets - Corporate to Regulated Electric & Gas Utilities - United States | 108 | - | |||
| Other inter-segment assets | 31 | 18 | |||
| Total inter-segment eliminations | $ | 207 | $ | 440 | |
6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS
| (in millions) | 2015 | 2014 | ||||
| Trade accounts receivable | $ | 517 | $ | 479 | ||
| Unbilled accounts receivable | 404 | 365 | ||||
| Allowance for doubtful accounts | (66 | ) | (31 | ) | ||
| Income tax receivable | - | 25 | ||||
| Assets held for sale | 38 | - | ||||
| Other | 71 | 62 | ||||
| $ | 964 | $ | 900 |
The increase in the allowance for doubtful accounts was primarily due to an increase in the reserve for uncollectible accounts at UNS Energy in relation to billings to third-party owners of Springerville Unit 1 for their pro-rata share of costs to operate the facility. Due to ongoing litigation and uncertainty with Springerville Unit 1 third-party owners, the accounts receivable balance of $32 million (US$23 million) as at December 31, 2015 associated with operating expenses has been fully reserved (Note 34).
Assets held for sale include utility capital assets of approximately $29 million (US$21 million) purchased by UNS Energy upon expiration of the Springerville Coal Handling Facilities lease in April 2015 (Note 16). UNS Energy has an agreement with a third party whereby they can purchase a 17.05% interest or continue to make payments to UNS Energy for the use of the facility. The third party has until April 2016 to exercise its purchase option and, as a result, the assets have been classified as held for sale on the consolidated balance sheet as at December 31, 2015.
Additionally, in December 2015 FortisBC Electric entered into an agreement to sell the non-regulated Walden hydroelectric power plant assets for a sale price of approximately $9 million (Note 31). The sale is expected to close in the first quarter of 2016. For the year ended December 31, 2015, earnings before taxes of less than $1 million were recognized (December 31, 2014 - less than $1 million) associated with Walden.
Other accounts receivable consisted of customer billings for non-core services, collateral deposits for gas purchases at FortisBC Energy and advances on coal purchases at UNS Energy. Other accounts receivable also included the fair value of derivative instruments (Note 31).
7. INVENTORIES
| (in millions) | 2015 | 2014 | ||
| Materials and supplies | $ | 194 | $ | 149 |
| Gas and fuel in storage | 101 | 134 | ||
| Coal inventory | 42 | 38 | ||
| $ | 337 | $ | 321 |
Materials and supplies included approximately $152 million (December 31, 2014 - $118 million) at UNS Energy, and consisted of construction and repair materials for distribution, transmission and generation assets, as required by the regulator (Note 3).
8. REGULATORY ASSETS AND LIABILITIES
Based on previous, existing or expected regulatory orders or decisions, the Corporation's regulated utilities have recorded the following amounts that are expected to be recovered from, or refunded to, customers in future periods.
| Remaining | |||||||
| recovery period | |||||||
| (in millions) | 2015 | 2014 | (Years) | ||||
| Regulatory assets | |||||||
| Deferred income taxes (i) | $ | 936 | $ | 832 | To be determined | ||
| Employee future benefits (ii) | 627 | 680 | Various | ||||
| Deferred energy management costs (iii) | 145 | 111 | 1-10 | ||||
| Manufactured gas plant ("MGP") site remediation deferral (iv) | 121 | 123 | To be determined | ||||
| Rate stabilization accounts (v) | 119 | 119 | Various | ||||
| Deferred lease costs (vi) | 90 | 101 | Various | ||||
| Derivative instruments (vii) | 74 | 69 | Various | ||||
| Deferred operating overhead costs (viii) | 66 | 54 | Various | ||||
| Final mine reclamation and retiree health care costs (ix) | 39 | 34 | 1-22 | ||||
| Deferred net losses on disposal of utility capital assets and intangible assets (x) | 33 | 37 | 8 | ||||
| Springerville Unit 1 unamortized leasehold improvements (xi) | 30 | - | 8 | ||||
| Property tax deferrals (xii) | 30 | 29 | 1 | ||||
| Other regulatory assets (xiii) | 222 | 226 | Various | ||||
| Total regulatory assets | 2,532 | 2,415 | |||||
| Less: current portion | (246 | ) | (277 | ) | 1 | ||
| Long-term regulatory assets | $ | 2,286 | $ | 2,138 | |||
| Regulatory liabilities | |||||||
| Non-ARO removal cost provision (xiv) | $ | 1,060 | $ | 951 | To be determined | ||
| Rate stabilization accounts (v) | 212 | 142 | Various | ||||
| Electric and gas moderator account (xv) | 88 | - | To be determined | ||||
| Renewable energy surcharge (xvi) | 47 | 44 | To be determined | ||||
| Employee future benefits (ii) | 44 | 58 | Various | ||||
| Customer and community benefits obligation (xvii) | 32 | 55 | To be determined | ||||
| AESO charges deferral (xviii) | 25 | 49 | 1-4 | ||||
| Other regulatory liabilities (xix) | 130 | 146 | Various | ||||
| Total regulatory liabilities | 1,638 | 1,445 | |||||
| Less: current portion | (298 | ) | (173 | ) | 1 | ||
| Long-term regulatory liabilities | $ | 1,340 | $ | 1,272 |
Description of the Nature of Regulatory Assets and Liabilities
(i) Deferred Income Taxes
The Corporation's regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future electricity and gas rates. Included in deferred income tax assets and liabilities are the future income tax effects of the subsequent settlement of the related regulatory liabilities and assets through customer rates. The deferred income taxes on regulatory assets and liabilities are the result of the application of ASC Topic 740, Income Taxes. The regulatory asset balances are expected to be recovered from customers in future rates when the income taxes become payable or receivable. As at December 31, 2015, $351 million (December 31, 2014 - $265 million) in regulatory assets for deferred income taxes was not subject to a regulatory return.
(ii) Employee Future Benefits
The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation's regulated utilities, which are expected to be recovered from, or refunded to, customers in future rates (Note 27). At the Corporation's regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet.
As at December 31, 2015, regulatory assets of approximately $367 million associated with employee future benefits were not subject to a regulatory return (December 31, 2014 - $339 million). As at December 31, 2015, regulatory liabilities of approximately $36 million associated with employee future benefits were not subject to a regulatory return (December 31, 2014 - $55 million).
(iii) Deferred Energy Management Costs
FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years. This regulatory asset represents the unamortized balance of the energy management costs.
UNS Energy is required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2015, $25 million of UNS Energy's regulatory asset balance was not subject to a regulatory return (December 31, 2014 - $16 million).
(iv) MGP Site Remediation Deferral
As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 14, 17 and 34). Central Hudson's MGP site remediation costs are not subject to a regulatory return.
(v) Rate Stabilization Accounts
Rate stabilization accounts associated with the Corporation's regulated electric and gas utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulatory authority. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms that minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility.
As at December 31, 2015, approximately $49 million and $142 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively (December 31, 2014 - approximately $105 million and $43 million, respectively).
As at December 31, 2015, regulatory assets of approximately $44 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2014 - $104 million). As at December 31, 2015, regulatory liabilities of approximately $76 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2014 - $42 million).
(vi) Deferred Lease Costs
Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA"), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered by FortisBC Electric in current customer rates, since those rates include only the cash payments set out under the BPPA. The regulatory asset balance as at December 31, 2015 included $90 million (December 31, 2014 - $83 million) of deferred lease costs that are expected to be recovered from customers in future rates over the term of the lease. In 2015, of the $30 million (2014 - $30 million) of interest expense related to the capital lease obligations and the $6 million (2014 - $6 million) of depreciation expense related to the assets under capital lease, a total of $26 million (2014 - $26 million) was recognized in energy supply costs and $3 million (2014 - $3 million) was recognized in operating expenses, respectively, as approved by the regulator, with the balance of $7 million (2014 - $7 million) deferred as a regulatory asset (Note 16).
The regulatory asset balance as at December 31, 2014 included $18 million of deferred lease costs at UNS Energy related to the remaining purchase commitments of Springerville Unit 1 and the Springerville Coal Handling Facility, of which both purchases occurred in 2015 (Note 16).
Deferred lease costs are not subject to a regulatory return.
(vii) Derivative Instruments
As approved by the respective regulatory authority, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings (Note 31). UNS Energy and Central Hudson's deferred regulatory asset balance totalling $57 million as at December 31, 2015 was not subject to a regulatory return (December 31, 2014 - $57 million).
(viii) Deferred Operating Overhead Costs
As approved by the regulator, FortisAlberta has deferred certain operating overhead costs. The deferred costs are expected to be collected in future customer rates over the lives of the related utility capital assets and intangible assets.
(ix) Final Mine Reclamation and Retiree Health Care Costs
Final mine reclamation and retiree health care costs are associated with TEP's jointly owned coal generating facilities at the San Juan, Four Corners and Navajo generating stations. TEP has the option to recognize its liability associated with final mine reclamation and retiree health care obligations at present or future value (Notes 17 and 34). TEP has elected to recognize these costs at future value and is permitted to fully recover these costs from customers through its rate stabilization accounts when the costs are paid. TEP expects to make continuous payments through 2037. These deferred costs are not subject to a regulatory return.
(x) Deferred Net Losses on Disposal of Utility Capital Assets and Intangible Assets
As approved by the regulator, from 2010 through 2013 net losses on the retirement or disposal of utility capital assets and intangible assets at FortisBC Energy were recorded in a regulatory deferral account to be recovered from customers in future rates. The regulator approved the recovery in customer rates of the resulting regulatory asset over a period of 10 years.
(xi) Springerville Unit 1 Unamortized Leasehold Improvements
Upon expiration of TEP's Springerville Unit 1 capital lease in January 2015, unamortized leasehold improvements were reclassified from utility capital assets to regulatory assets. The leasehold improvements represent investments made by TEP through the end of the lease term to ensure Springerville facilities continued providing safe, reliable service to TEP's customers. In its 2013 rate order, TEP received regulatory approval to amortize the leasehold improvements over a 10-year period. TEP continues to own an undivided 49.5% joint interest in Springerville Unit 1.
(xii) Property Tax Deferrals
Property taxes at UNS Energy and Central Hudson are deferred and are primarily collected from customers over a six-month to one-year period, as approved by the respective regulator. Property tax deferrals are not subject to a regulatory return.
(xiii) Other Regulatory Assets
Other regulatory assets relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $30 million. As at December 31, 2015, $189 million (December 31, 2014 - $177 million) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2015, $69 million (December 31, 2014 - $74 million) of the balance was not subject to a regulatory return.
(xiv) Non-ARO Removal Cost Provision
As required by the respective regulator, depreciation rates at UNS Energy, Central Hudson, FortisBC Energy, FortisAlberta, Newfoundland Power and Maritime Electric include an amount allowed for regulatory purposes to accrue for non-ARO removal costs. Actual non-ARO removal costs are recorded against the regulatory liability when incurred. This regulatory liability represents amounts collected in customer electricity rates at the respective utilities in excess of incurred non-ARO removal costs.
(xv) Electric and Gas Moderator Account
Under the terms of Central Hudson's three-year Rate Order issued in June 2015, certain of the Company's regulatory assets and liabilities were identified and approved by the PSC for offset and a net regulatory liability electric and gas moderator account was established, which will be used for future customer rate moderation. These electric and gas moderator accounts are not subject to a regulatory return.
(xvi) Renewable Energy Surcharge
As ordered by the regulator under its Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. The Company must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes and a return on investments on certain company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory asset or liability.
The ACC measures compliance with its RES requirements through Renewable Energy Credits ("REC"), which represent one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records the cost of the RECs as long-term other assets and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount (Note 9).
(xvii) Customer and Community Benefits Obligation
As approved by the respective regulator for UNS Energy and Central Hudson, Fortis committed to provide their customers and community with financial benefits that would have not been realized in the absence of the acquisitions. These commitments resulted in the recognition of regulatory liabilities to be used to mitigate future customer rate increase at the utilities. In 2014 these commitments for UNS Energy's customers included US$10 million in year one and US$5 million in years two through five to cover credits in retail customer rates. As a result, expenses of approximately $33 million (US$30 million) were recognized in 2014 related to the acquisition of UNS Energy for customer benefit obligations (Notes 24 and 29).
(xviii) AESO Charges Deferral
FortisAlberta maintains an AESO charges deferral account that represents expenses incurred in excess of revenue collected for various items, such as transmission costs incurred and flowed through to customers, that are subject to deferral to be collected in future customer rates. To the extent that the amount of revenue collected in rates for these items exceeds actual costs incurred, the excess is deferred as a regulatory liability to be refunded in future customer rates. As at December 31, 2015, the regulatory liability primarily represented the over collection of the AESO charges deferral accounts for 2014 and 2015.
(xix) Other Regulatory Liabilities
Other regulatory liabilities relate to all of the Corporation's regulated utilities and are comprised of various items, each individually less than $30 million. As at December 31, 2015, $120 million (December 31, 2014 - $140 million) of the balance was approved for refund to customers or reduction in future rates, with the remaining balance expected to be approved. As at December 31, 2015, $68 million (December 31, 2014 - $76 million) of the balance was not subject to a regulatory return.
9. OTHER ASSETS
| (in millions) | 2015 | 2014 | ||
| Equity investment - Belize Electricity | $ | 79 | $ | - |
| Supplemental Executive Retirement Plan assets | 58 | 41 | ||
| Deposit on pending business acquisition (Note 29) | 38 | - | ||
| Available-for-sale investment (Notes 28 and 31) | 33 | - | ||
| Deferred compensation plan assets (Note 17) | 25 | 21 | ||
| Renewable Energy Credits (Note 8 (xvi)) | 17 | 13 | ||
| Long-term income tax receivable | 13 | 13 | ||
| Other investments | 13 | 12 | ||
| Other asset - Belize Electricity | - | 116 | ||
| Other | 76 | 56 | ||
| $ | 352 | $ | 272 |
In August 2015 the Corporation agreed to terms of a settlement with the GOB regarding the GOB's expropriation of the Corporation's approximate 70% interest in Belize Electricity in June 2011. The terms of the settlement included a one-time US$35 million cash payment to Fortis from the GOB and an approximate 33% equity investment in Belize Electricity. As a result of the settlement, the Corporation recognized an approximate $9 million loss in 2015 (Note 24).
UNS Energy and Central Hudson provide additional post-employment benefits through both a deferred compensation plan for Directors and Officers of the Companies, as well as Supplemental Executive Retirement Plans ("SERP"). Since both plans are considered non-qualified plans under the Employee Retirement Income Security Act of 1974, the assets are reported separately from the related liabilities (Note 17). The assets of the plans are held in trust and funded mostly through the use of trust-owned life insurance policies and mutual funds. A portion of the SERP assets is invested in corporate-owned life insurance policies. Amounts held in mutual and money market funds are recorded at fair value (Note 31).
In June 2015 the Corporation completed the sale of commercial real estate assets for gross proceeds of $430 million (Note 28). As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering. The investment in trust units is recorded as an available-for-sale asset. The assets are measured at fair value based on quoted market prices and unrealized gains or losses resulting from changes in fair value are recognized in accumulated other comprehensive income and are reclassified to earnings when the assets are sold (Notes 21 and 31).
Other assets are recorded at cost and are recovered or amortized over the estimated period of future benefit, where applicable. Other assets include the fair value of derivative instruments at UNS Energy and Central Hudson (Note 31).
10. UTILITY CAPITAL ASSETS
| 2015 | ||||||||
| Accumulated | Net Book | |||||||
| (in millions) | Cost | Depreciation | Value | |||||
| Distribution | ||||||||
| Electric | $ | 9,245 | $ | (2,634 | ) | $ | 6,611 | |
| Gas | 3,829 | (1,021 | ) | 2,808 | ||||
| Transmission | ||||||||
| Electric | 3,093 | (997 | ) | 2,096 | ||||
| Gas | 1,735 | (531 | ) | 1,204 | ||||
| Generation | 6,465 | (2,241 | ) | 4,224 | ||||
| Other | 2,429 | (849 | ) | 1,580 | ||||
| Assets under construction | 886 | - | 886 | |||||
| Land | 186 | - | 186 | |||||
| $ | 27,868 | $ | (8,273 | ) | $ | 19,595 | ||
| 2014 | ||||||||
| Accumulated | Net Book | |||||||
| (in millions) | Cost | Depreciation | Value | |||||
| Distribution | ||||||||
| Electric | $ | 8,102 | $ | (2,317 | ) | $ | 5,785 | |
| Gas | 3,475 | (920 | ) | 2,555 | ||||
| Transmission | ||||||||
| Electric | 2,562 | (859 | ) | 1,703 | ||||
| Gas | 1,649 | (491 | ) | 1,158 | ||||
| Generation | 5,296 | (2,189 | ) | 3,107 | ||||
| Other | 2,158 | (731 | ) | 1,427 | ||||
| Assets under construction | 1,277 | - | 1,277 | |||||
| Land | 167 | - | 167 | |||||
| $ | 24,686 | $ | (7,507 | ) | $ | 17,179 | ||
Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kV). These assets include poles, towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kPa) or a hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment.
Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include transmission stations, telemetry, transmission pipe and other related equipment.
Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems and other related equipment.
Other assets include buildings, equipment, vehicles, inventory and information technology assets.
Construction of the Waneta Expansion was completed in April 2015. As at December 31, 2015, assets under construction are primarily associated with FortisBC Energy's Tilbury liquefied natural gas facility expansion and other capital projects at the Corporation's regulated utilities.
The cost of utility capital assets under capital lease as at December 31, 2015 was $496 million (December 31, 2014 - $1,088 million) and related accumulated depreciation was $221 million (December 31, 2014 - $627 million). The decrease was primarily due to the purchase of certain utility capital assets at TEP in 2015 following the expiry of lease arrangements (Note 16).
Jointly Owned Facilities
As at December 31, 2015, UNS Energy's interests in jointly owned generating stations and transmission systems primarily consisted of the following:
| 2015 | ||||||||
| Ownership | Accumulated | Net Book | ||||||
| (in millions) | % | Cost | Depreciation | Value | ||||
| San Juan Units 1 and 2 | 50.0 | $ | 690 | $ | (347 | ) | $ | 343 |
| Navajo Units 1, 2 and 3 | 7.5 | 207 | (155 | ) | 52 | |||
| Four Corners Units 4 and 5 | 7.0 | 154 | (107 | ) | 47 | |||
| Luna Energy Facility | 33.3 | 75 | (1 | ) | 74 | |||
| Gila River Common Facilities | 25.0 | 47 | (14 | ) | 33 | |||
| Springerville Unit 1 (1) | 49.5 | 452 | (240 | ) | 212 | |||
| Springerville Coal Handling Facilities (2) | 65.9 | 228 | (90 | ) | 138 | |||
| Transmission Facilities | Various | 531 | (238 | ) | 293 | |||
| $ | 2,384 | $ | (1,192 | ) | $ | 1,192 | ||
| (1) | TEP is obligated to operate the unit for third-party owners under existing agreements. The third-party owners are obligated to compensate TEP for their pro rata share of expenses (Notes 16 and 34). |
| (2) | TEP owns an additional 17.05% undivided interest in the Springerville Coal Handling Facilities, which is classified as assets held for sale (Notes 6 and 16). |
UNS Energy holds an undivided interest in the above facilities and is entitled to its pro rata share of the utility capital assets. UNS Energy is proportionately liable for its share of operating costs and liabilities in respect of the jointly owned facilities.
11. NON-UTILITY CAPITAL ASSETS
In 2015 the Corporation sold its commercial real estate and hotel assets (Note 28). As a result, the Corporation did not hold any non-utility capital assets as at December 31, 2015.
| 2014 | ||||||
| Accumulated | Net Book | |||||
| (in millions) | Cost | Depreciation | Value | |||
| Buildings | $ | 599 | $ | (105) | $ | 494 |
| Equipment | 145 | (73) | 72 | |||
| Tenant inducements | 35 | (27) | 8 | |||
| Land | 72 | - | 72 | |||
| Assets under construction | 18 | - | 18 | |||
| $ | 869 | $ | (205) | $ | 664 | |
12. INTANGIBLE ASSETS
| 2015 | |||||||
| Accumulated | Net Book | ||||||
| (in millions) | Cost | Amortization | Value | ||||
| Computer software | $ | 685 | $ | (436 | ) | $ | 249 |
| Land, transmission and water rights | 328 | (76 | ) | 252 | |||
| Franchise fees and other | 17 | (13 | ) | 4 | |||
| Assets under construction | 36 | - | 36 | ||||
| $ | 1,066 | $ | (525 | ) | $ | 541 | |
| 2014 | |||||||
| Accumulated | Net Book | ||||||
| (in millions) | Cost | Amortization | Value | ||||
| Computer software | $ | 573 | $ | (368 | ) | $ | 205 |
| Land, transmission and water rights | 258 | (66 | ) | 192 | |||
| Franchise fees and other | 16 | (12 | ) | 4 | |||
| Assets under construction | 60 | - | 60 | ||||
| $ | 907 | $ | (446 | ) | $ | 461 | |
Included in the cost of land, transmission and water rights as at December 31, 2015 was $106 million (December 31, 2014 - $77 million) not subject to amortization.
Amortization expense related to intangible assets was $64 million for 2015 (2014 - $60 million). Amortization is estimated to average approximately $78 million annually for each of the next five years.
13. GOODWILL
| (in millions) | 2015 | 2,014 | |||
| Balance, beginning of year | $ | 3,732 | $ | 2,075 | |
| Acquisition of UNS Energy (Note 29) | - | 1,510 | |||
| Sale of Griffith (Note 28) | - | (3 | ) | ||
| Foreign currency translation impacts | 441 | 150 | |||
| Balance, end of year | $ | 4,173 | $ | 3,732 |
Goodwill associated with the acquisitions of UNS Energy, Central Hudson, Caribbean Utilities and Fortis Turks and Caicos is denominated in US dollars, as the functional currency of these companies is the US dollar. Foreign currency translation impacts are the result of the translation of US dollar-denominated goodwill and the impact of the movement of the Canadian dollar relative to the US dollar.
14. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES
| (in millions) | 2015 | 2014 | ||
| Trade accounts payable | $ | 574 | $ | 612 |
| Gas and fuel cost payable | 153 | 195 | ||
| Employee compensation and benefits payable | 137 | 134 | ||
| Interest payable | 127 | 128 | ||
| Dividends payable | 113 | 101 | ||
| Accrued taxes other than income taxes | 108 | 96 | ||
| Fair value of derivative instruments (Note 31) | 69 | 66 | ||
| MGP site remediation (Notes 8 (iv), 17 and 34) | 32 | 13 | ||
| Defined benefit pension and OPEB plan liabilities (Note 27) | 13 | 11 | ||
| Other | 93 | 84 | ||
| $ | 1,419 | $ | 1,440 |
Accrued taxes other than income taxes primarily consisted of property taxes at UNS Energy and carbon tax at FortisBC Energy.
15. LONG-TERM DEBT
| (in millions) | Maturity Date | 2015 | 2014 | ||||
| Regulated Utilities | |||||||
| UNS Energy | |||||||
| Unsecured US Tax-Exempt Bonds - 3.83% weighted average fixed and variable rate (2014 - 3.92%) | 2020-2040 | $ | 848 | $ | 956 | ||
| Unsecured US Fixed Rate Notes - 4.26% weighted average fixed rate (2014 - 4.98%) | 2021-2045 | 1,557 | 754 | ||||
| Secured US Fixed Rate Notes - 5.38% weighted average fixed and variable rate (2014 - 5.38%) | 2023-2026 | - | 151 | ||||
| Central Hudson | |||||||
| Unsecured US Promissory Notes - 4.30% weighted average fixed and variable rate (2014 - 4.31%) | 2016-2042 | 728 | 587 | ||||
| FortisBC Energy | |||||||
| Secured Purchase Money Mortgages - 10.30% weighted average fixed rate (2014 - 10.71%) | 2016 | 200 | 275 | ||||
| Unsecured Debentures - 5.73% weighted average fixed rate (2014 - 5.95%) | 2029-2045 | 1,770 | 1,620 | ||||
| Government loan | 2016 | 5 | 10 | ||||
| FortisAlberta | |||||||
| Unsecured Debentures - 4.95% weighted average fixed rate (2014 - 5.01%) | 2024-2052 | 1,684 | 1,534 | ||||
| FortisBC Electric | |||||||
| Secured Debentures - 8.80% weighted average fixed rate (2014 - 8.80%) | 2023 | 25 | 25 | ||||
| Unsecured Debentures - 5.36% weighted average fixed rate (2014 - 5.36%) | 2016-2050 | 660 | 660 | ||||
| Eastern Canadian | |||||||
| Secured First Mortgage Sinking Fund Bonds - 6.72% weighted average fixed rate (2014 - 7.08%) | 2016-2045 | 553 | 484 | ||||
| Secured First Mortgage Bonds - 7.18% weighted average fixed rate (2014 - 7.18%) | 2016-2061 | 167 | 167 | ||||
| Unsecured Senior Notes - 6.11% weighted average fixed rate (2014 - 6.11%) | 2018-2041 | 104 | 104 | ||||
| Caribbean Electric | |||||||
| Unsecured US Senior Loan Notes - 4.89% weighted average fixed rate (2014 - 4.91%) | 2016-2046 | 467 | 400 | ||||
| Non-Regulated - Non-Utility | |||||||
| Secured First Mortgages and Senior Notes - 7.46% weighted average fixed rate (2014 - 7.46%) | n/a | - | 34 | ||||
| Corporate | |||||||
| Unsecured US Senior Notes and Promissory Notes - 4.43% weighted average fixed rate (2014 - 4.43%) | 2019-2044 | 1,720 | 1,443 | ||||
| Unsecured Debentures 6.49% weighted average fixed rate (2014 - 6.49%) | 2039 | 201 | 201 | ||||
| Long-term classification of credit facility borrowings (Note 31) | 551 | 1,096 | |||||
| Total long-term debt (Note 31) | 11,240 | 10,501 | |||||
| Less: Deferred financing costs (Notes 3 and 36) | (72 | ) | (65 | ) | |||
| Less: Current installments of long-term debt | (384 | ) | (525 | ) | |||
| $ | 10,784 | $ | 9,911 | ||||
As noted in the previous table, certain long-term debt instruments issued by UNS Energy, FortisBC Energy, FortisBC Electric, Newfoundland Power, and Maritime Electric are secured. When security is provided, it is typically a fixed or floating first charge on the specific assets of the Company to which the long-term debt is associated. The purchase money mortgages of FortisBC Energy are secured equally and ratably by a first fixed and specific mortgage and charge on the Company's coastal division assets. The aggregate principal amount of the purchase money mortgages that may be issued is limited to $350 million.
UNS Energy entered into a four-year US$30 million variable rate term loan credit agreement and, at the same time, entered into a fixed-for-floating interest rate swap. Both the term loan and interest rate swap expired in 2015. The interest rate swap was designated as a cash flow hedge (Note 31).
Covenants
Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70% of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. In addition, one of the Corporation's long-term debt obligations contains a covenant which provides that Fortis shall not declare or pay any dividends, other than stock dividends or cumulative preferred dividends on preference shares not issued as stock dividends, or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization.
As at December 31, 2015, the Corporation and its subsidiaries were in compliance with their debt covenants.
Regulated Utilities
The majority of the long-term debt instruments at the Corporation's regulated utilities are redeemable at the option of the respective utilities, at any time, at the greater of par or a specified price as defined in the respective long-term debt agreements, together with accrued and unpaid interest.
In January 2015 TEP redeemed at par US$130 million of fixed rate tax-exempt bonds that had an original maturity date of 2029. As at December 31, 2015, TEP had not remarketed the repurchase bonds.
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.
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 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.
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 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.
In August 2015 UNS Electric issued 12-year US$80 million 3.22% unsecured debentures and UNS Gas issued 30-year US$45 million 4.00% unsecured notes. The net proceeds were used to repay maturing long-term debt. Additionally, in August 2015 TEP redeemed at par US$79 million of variable rate tax-exempt bonds that had an original maturity date of 2022.
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.
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.
Corporate
The unsecured debentures and US senior notes are redeemable at the option of Fortis at a price calculated as the greater of par or a specified price as defined in the respective long-term debt agreements, together with accrued and unpaid interest.
Repayment of Long-Term Debt
The consolidated annual requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows:
| Subsidiaries | Corporate | Total | ||||
| Year | (in millions) | (in millions) | (in millions) | |||
| 2016 | $ | 382 | $ | 2 | $ | 384 |
| 2017 | 69 | 2 | 71 | |||
| 2018 | 281 | 2 | 283 | |||
| 2019 | 112 | 127 | 239 | |||
| 2020 | 202 | 655 | 857 | |||
| Thereafter | 7,793 | 1,613 | 9,406 | |||
| $ | 8,839 | $ | 2,401 | $ | 11,240 | |
16. CAPITAL LEASE AND FINANCE OBLIGATIONS
Capital Lease Obligations
UNS Energy
In 2014 and 2015, TEP purchased certain Springerville assets upon expiry of the lease arrangements, as detailed below. As at December 31, 2015, capital lease obligations at TEP consist of an undivided one-half interest in certain Springerville Common Facilities.
Springerville Unit 1 Capital Lease Purchases
In December 2014 and January 2015, upon expiration of the Springerville Unit 1 lease, TEP purchased an additional 35.4% ownership interest in the previously leased assets for US$20 million and US$46 million, respectively. As a result of the purchases, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the third-party owners under an existing agreement. The third-party owners are obligated to compensate TEP for their pro rata share of expenditures (Note 34).
Springerville Coal Handling Facilities Lease Purchase
In April 2015, upon expiration of the Springerville Coal Handling Facilities lease, TEP purchased an 86.7% ownership interest in the previously leased coal handling assets for a total of US$120 million. In May 2015 TEP sold a 17.05% interest in the facilities to a third party for US$24 million and has an agreement with another third party to either purchase a 17.05% interest for US$24 million or to continue to make payments to TEP for the use of the facility. The third party has until April 2016 to exercise its purchase option and, as a result, the associated assets have been classified as held for sale on the consolidated balance sheet as at December 31, 2015 (Note 6).
Springerville Common Facilities Leases
TEP is party to three Springerville Common Facilities leases, which have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025 (Note 33). Instead of extending the leases, TEP may exercise a fixed-price purchase provision of US$38 million in 2017 and US$68 million in 2021. TEP has agreements with third parties that if the Springerville Common Facilities leases are not renewed, TEP will exercise the purchase options under these contracts. The third parties would be obligated to buy a portion of these facilities or continue to make payments to TEP for the use of these facilities.
UNS Energy entered into an interest rate swap that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. As at December 31, 2015, interest on the lease debt is payable at a six-month LIBOR plus a spread of 1.88% (December 31, 2014 - 1.75%). The swap has the effect of fixing the interest rates on a portion of the amortizing principal balances of US$29 million (December 31, 2014 - US$33 million). The interest rate swap expires in 2020 and is recorded as a cash flow hedge (Note 31).
The Springerville Common Facilities capital lease obligation bears interest at a rate of 5.08%. For the year ended December 31, 2015, in total $5 million (December 31, 2014 - $2 million) of interest expense on the Springerville capital lease obligations was recognized in finance charges and $3 million (December 31, 2014 - $3 million) and $8 million (December 31, 2014 - $7 million) of depreciation expense on the Springerville leased assets was recognized in energy supply costs and depreciation, respectively.
FortisBC Electric
FortisBC Electric has a capital lease obligation with respect to the operation of the Brilliant Plant located near Castlegar, British Columbia. FortisBC Electric operates and maintains the Brilliant Plant, under the BPPA which expires in 2056, in return for a management fee. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, comprised of the original plant capital charge and periodic upgrade capital charges, which are both subject to fixed annual escalators, as well as sustaining capital charges and operating expenses. The BPPA includes a market-related price adjustment in 2026. Due to the fixed annual escalators, the interest expense on the capital lease obligation presently exceeds the required payments. The capital lease obligation will continue to increase through to 2024, and subsequently decrease for the remainder of the term when the required payments exceed the interest expense on the capital lease obligation. Approximately 94% of the output from the Brilliant Plant is being purchased by FortisBC Electric through the BPPA.
The BPPA capital lease obligation bears interest at a composite rate of 5.00%. Included in energy supply costs for 2015 was $26 million (2014 - $26 million) recognized in accordance with the BPPA, as approved by the BCUC (Note 8 (vi)).
FortisBC Electric also has a capital lease obligation with respect to the operation of the Brilliant Terminal Station ("BTS"), under an agreement which expires in 2056. The agreement provides that FortisBC Electric will pay a charge related to the recovery of the capital cost of the BTS and related operating costs. The obligation bears interest at a composite rate of 9.00%. Included in operating expenses for 2015 was $3 million (2014 - $3 million) recognized in accordance with the BTS agreement, as approved by the BCUC (Note 8 (vi)).
Finance Obligations
Between 2000 and 2005 FEI entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FEI from the municipalities. The natural gas distribution assets are considered to be integral equipment to real estate assets and, as such, the transactions have been accounted for as finance transactions. The proceeds from these transactions have been recognized as finance obligations on the consolidated balance sheet. Lease payments, net of the portion considered to be interest expense, reduce the finance obligations.
Obligations under the above-noted lease-in lease-out transactions at FEI have implicit interest at rates ranging from 6.82% to 8.66% and are being repaid over a 35-year period. Each of the lease-in lease-out arrangements allows FEI, at its option, to terminate the lease arrangements early, after 17 years. If the Company exercises this option, FEI would pay the municipality an early termination payment which is equal to the carrying value of the obligation at that point in time.
Repayment of Capital Lease and Finance Obligations
The present value of the minimum lease payments required for the capital lease and finance obligations over the next five years and thereafter are as follows:
| Capital | Finance | ||||||
| Leases | Obligations | Total | |||||
| Year | (in millions) | (in millions) | (in millions) | ||||
| 2016 | $ | 68 | $ | 4 | $ | 72 | |
| 2017 | 70 | 4 | 74 | ||||
| 2018 | 61 | 32 | 93 | ||||
| 2019 | 62 | 15 | 77 | ||||
| 2020 | 73 | 2 | 75 | ||||
| Thereafter | 2,049 | 38 | 2,087 | ||||
| $ | 2,383 | $ | 95 | $ | 2,478 | ||
| Less: Amounts representing imputed interest and | |||||||
| executory costs on capital lease and finance obligations | (1,965 | ) | |||||
| Total capital lease and finance obligations | 513 | ||||||
| Less: Current portion | (26 | ) | |||||
| $ | 487 | ||||||
17. OTHER LIABILITIES
| (in millions) | 2015 | 2014 | ||
| OPEB plan liabilities (Note 27) | $ | 385 | $ | 403 |
| Defined benefit pension plan liabilities (Note 27) | 368 | 390 | ||
| MGP site remediation (Notes 8 (iv), 14 and 34) | 96 | 109 | ||
| Waneta Partnership promissory note (Notes 31 and 33) | 56 | 53 | ||
| Asset retirement obligations | 49 | 37 | ||
| Final mine reclamation and retiree health care liabilities (Notes 8 (ix) and 34) | 39 | 34 | ||
| Customer security deposits | 38 | 26 | ||
| Deferred compensation plan liabilities (Note 9) | 25 | 21 | ||
| DSU, PSU and RSU liabilities (Note 23) | 20 | 17 | ||
| Fair value of derivative instruments (Note 31) | 13 | 13 | ||
| Other | 63 | 38 | ||
| $ | 1,152 | $ | 1,141 | |
The Waneta Partnership promissory note is non-interest bearing with a face value of $72 million. As at December 31, 2015, its discounted net present value was $56 million (December 31, 2014 - $53 million). The promissory note was incurred by the Waneta Partnership on the acquisition of certain intangible assets and project design costs, from a company affiliated with CPC/CBT, associated with the construction of the Waneta Expansion. The promissory note is payable on April 1, 2020, the fifth anniversary of the commercial operation date of the Waneta Expansion.
As at December 31, 2015, UNS Energy, Central Hudson and FortisBC Electric recognized asset retirement obligations.
Other liabilities primarily include long-term accrued liabilities, deferred lease revenue, funds received in advance of expenditures and unrecognized tax benefits.
18. COMMON SHARES
Common shares issued during the year were as follows:
| 2015 | 2014 | |||||
| Number | Number | |||||
| of Shares | Amount | of Shares | Amount | |||
| (in thousands) | (in millions) | (in thousands) | (in millions) | |||
| Balance, beginning of year | 275,997 | $ | 5,667 | 213,165 | $ | 3,783 |
| Conversion of Convertible Debentures | 24 | 1 | 58,545 | 1,747 | ||
| Dividend Reinvestment Plan | 4,272 | 157 | 2,495 | 82 | ||
| Consumer Share Purchase Plan | 28 | 1 | 33 | 1 | ||
| Employee Share Purchase Plan | 356 | 13 | 384 | 12 | ||
| Stock Option Plans | 885 | 28 | 1,375 | 42 | ||
| Balance, end of year | 281,562 | $ | 5,867 | 275,997 | $ | 5,667 |
Convertible Debentures
To finance a portion of the acquisition of UNS Energy, in January 2014, Fortis completed the sale of $1.8 billion aggregate principal amount of 4% convertible unsecured subordinated debentures, represented by Installment Receipts ("Convertible Debentures"). The Convertible Debentures were sold on an installment basis at a price of $1,000 per Convertible Debenture, of which $333 was paid on closing in January 2014 and the remaining $667 was paid on October 27, 2014 (the "Final Installment Date"). Prior to the Final Installment Date, the Convertible Debentures were represented by Installment Receipts, which were traded on the TSX under the symbol "FTS.IR". Since the Final Installment Date occurred prior to the first anniversary of the closing of the offering, holders of Convertible Debentures received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing interest that would have accrued from the day following the Final Installment Date to and including January 9, 2015. Approximately $72 million ($51 million after tax) in interest expense associated with the Convertible Debentures, including the make-whole payment, was recognized in 2014 (Note 25).
At the option of the holders, each Convertible Debenture was convertible into common shares of Fortis at any time after the Final Installment Date but prior to maturity or redemption by the Corporation at a conversion price of $30.72 per common share, being a conversion rate of 32.5521 common shares per $1,000 principal amount of Convertible Debentures. On October 28, 2014, approximately 58.2 million common shares of Fortis were issued, representing conversion into common shares of more than 99% of the Convertible Debentures. As at December 31, 2015, a total of approximately 58.6 million common shares of Fortis were issued on the conversion of Convertible Debentures, for proceeds of $1.748 billion, net of after-tax expenses. The net proceeds were used to finance a portion of the acquisition of UNS Energy (Note 29).
19. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. The weighted average number of common shares outstanding was 278.6 million for 2015 and 225.6 million for 2014.
Diluted EPS was calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS were as follows:
| 2015 | |||||||||||
| Net Earnings to Common Shareholders | Weighted | ||||||||||
| (in millions) | Average | EPS | |||||||||
| Number of | |||||||||||
| Continuing | Discontinued | Shares | Continuing | Discontinued | |||||||
| Operations | Operations | Total | (millions) | Operations | Operations | Total | |||||
| Basic EPS | $728 | $- | $728 | 278.6 | $2.61 | $- | $2.61 | ||||
| Effect of potential dilutive securities: | |||||||||||
| Stock Options | - | - | - | 0.7 | |||||||
| Preference Shares | 10 | - | 10 | 5.4 | |||||||
| Diluted EPS | $738 | $- | $738 | 284.7 | $2.59 | $- | $2.59 | ||||
| 2014 | |||||||||||
| Net Earnings to Common Shareholders | Weighted | ||||||||||
| (in millions) | Average | EPS | |||||||||
| Number of | |||||||||||
| Continuing | Discontinued | Shares | Continuing | Discontinued | |||||||
| Operations | Operations | Total | (millions) | Operations | Operations | Total | |||||
| Basic EPS | $312 | $5 | $317 | 225.6 | $1.39 | $0.02 | $1.41 | ||||
| Effect of potential dilutive securities: | |||||||||||
| Stock Options | - | - | - | 0.5 | |||||||
| Preference Shares | 10 | - | 10 | 6.9 | |||||||
| 322 | 5 | 327 | 233.0 | ||||||||
| Deduct anti-dilutive impacts: | |||||||||||
| Preference Shares | (10 | ) | - | (10 | ) | (6.9 | ) | ||||
| Diluted EPS | $312 | $5 | $317 | 226.1 | $1.38 | $0.02 | $1.40 | ||||
20. PREFERENCE SHARES
Authorized
- an unlimited number of First Preference Shares, without nominal or par value
- an unlimited number of Second Preference Shares, without nominal or par value
| Issued and Outstanding | 2015 | 2014 | ||||||
| First Preference Shares | Annual Dividend Per Share | Number of Shares | | Amount (in millions) | Number of Shares | | Amount (in millions) | |
| Series E (1) | $ | 1.2250 | 7,993,500 | $ | 197 | 7,993,500 | $ | 197 |
| Series F (1) | $ | 1.2250 | 5,000,000 | 122 | 5,000,000 | 122 | ||
| Series G (2) | $ | 0.9708 | 9,200,000 | 225 | 9,200,000 | 225 | ||
| Series H (2) (3) | $ | 0.6250 | 7,024,846 | 172 | 10,000,000 | 245 | ||
| Series I (4) | 2,975,154 | 73 | - | - | ||||
| Series J (1) | $ | 1.1875 | 8,000,000 | 196 | 8,000,000 | 196 | ||
| Series K (2) | $ | 1.0000 | 10,000,000 | 244 | 10,000,000 | 244 | ||
| Series M (2) | $ | 1.0250 | 24,000,000 | 591 | 24,000,000 | 591 | ||
| 74,193,500 | $ | 1,820 | 74,193,500 | $ | 1,820 | |||
| (1) | Cumulative Redeemable First Preference Shares |
| (2) | Cumulative Redeemable Five-Year Fixed Rate Reset First Preference Shares |
| (3) | The annual fixed dividend per share for the First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from and including June 1, 2015 to but excluding June 1, 2020. |
| (4) | Cumulative Redeemable Five-Year Floating Rate Preference Shares. The floating quarterly dividend rate will be reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus 1.45%. |
In September 2014 the Corporation issued 24 million Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series M ("First Preference Shares, Series M") at a price of $25.00 per share for net after-tax proceeds of $591 million.
Holders of the First Preference Shares, Series E, Series F and Series J are each entitled to receive a fixed cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal quarterly installments on the first day of each quarter.
On or after September 1, 2016, each First Preference Share, Series E will be convertible at the option of the holder on the first day of September, December, March and June of each year into fully paid and freely tradeable common shares of the Corporation, determined by dividing $25.00, together with all accrued and unpaid dividends, by the greater of $1.00 or 95% of the then-current market price of the common shares at such time. If a holder of First Preference Shares, Series E elects to convert any such shares into common shares, the Corporation can redeem such First Preference Shares, Series E for cash or arrange for the sale of those shares to other purchasers.
The Corporation has the option to convert all, or from time to time any part, of the outstanding First Preference Shares, Series E into fully paid and freely tradeable common shares of the Corporation. The number of common shares into which each First Preference Share, Series E may be converted will be determined by dividing the then-applicable redemption price per First Preference Share, Series E, together with all accrued and unpaid dividends, by the greater of $1.00 or 95% of the then-current market price of the common shares at such time.
The First Preference Shares, Series G, Series H, Series K and Series M are entitled to receive fixed cumulative cash dividends as and when declared by the Board of Directors of the Corporation in the amounts of $0.9708, $0.6250, $1.0000 and $1.0250 per share per annum, respectively, for each year up to but excluding September 1, 2018, June 1, 2020, March 1, 2019, and December 1, 2019, respectively. The dividends are payable in equal quarterly installments on the first day of each quarter. As at September 1, 2018, June 1, 2020, March 1, 2019, and December 1, 2019, and each five-year period thereafter, the holders of First Preference Shares, Series G, Series H, Series K and Series M, respectively, are entitled to receive reset fixed cumulative cash dividends. The reset annual dividends per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate of the First Preference Shares, Series G, Series H, Series K and Series M, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.13%, 1.45%, 2.05% and 2.48%, respectively.
On each First Preference Shares, Series H, Series K and Series M Conversion Date, the holders of First Preference Shares, Series H, Series K and Series M have the option to convert any or all of their First Preference Shares, Series H, Series K and Series M into an equal number of cumulative redeemable floating rate First Preference Shares, Series I, Series L and Series N, respectively. On June 1, 2015, 2,975,154 of the 10,000,000 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I. As a result of the conversion, Fortis has issued and outstanding 7,024,846 First Preference Shares, Series H and 2,975,154 First Preference Shares, Series I.
The holders for First Preference Shares, Series I are entitled to receive floating rate cumulative cash dividends, as and when declared by the Board of Directors of the Corporation, for the five-year period beginning after June 1, 2015. The floating quarterly dividend rate will be reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus 1.45%. The holders of First Preference Shares Series L and Series N will be entitled to receive floating rate cumulative cash dividends in the amount per share determined by multiplying the applicable floating quarterly dividend rate by $25.00. The floating quarterly dividend rate of the First Preference Shares Series L and Series N will be equal to the sum of the average yield expressed as a percentage per annum on three-month Government of Canada Treasury Bills plus 2.05% and 2.48%, respectively.
On or after specified dates, the Corporation has the option to redeem for cash the outstanding First Preference Shares, in whole at any time or in part from time to time, at specified fixed prices per share plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.
21. ACCUMULATED OTHER COMPREHENSIVE INCOME
Other comprehensive income or loss results from items deferred from recognition in the consolidated statement of earnings. The change in accumulated other comprehensive income by category is provided as follows.
| 2015 | ||||||||||
| Opening | Ending | |||||||||
| balance | Net | balance | ||||||||
| (in millions) | January 1 | change | December 31 | |||||||
| Net unrealized foreign currency translation gains (losses): | ||||||||||
| Unrealized foreign currency translation gains on net investments in foreign operations | $ | 273 | $ | 1,008 | $ | 1,281 | ||||
| Losses on hedges of net investments in foreign operations | (131 | ) | (345 | ) | (476 | ) | ||||
| Income tax recovery | 2 | (1 | ) | 1 | ||||||
| 144 | 662 | 806 | ||||||||
| Available-for-sale investment: (Notes 9, 28 and 31) | ||||||||||
| Unrealized losses on available-for-sale investment | - | (2 | ) | (2 | ) | |||||
| Cash flow hedges: (Note 31) | ||||||||||
| Net change in fair value of cash flow hedges | 1 | 2 | 3 | |||||||
| Income tax expense | - | (1 | ) | (1 | ) | |||||
| 1 | 1 | 2 | ||||||||
| Unrealized employee future benefits (losses) gains: (Note 27) | ||||||||||
| Unamortized past service costs | (2 | ) | 1 | (1 | ) | |||||
| Unamortized net actuarial losses | (20 | ) | - | (20 | ) | |||||
| Income tax recovery | 6 | - | 6 | |||||||
| (16 | ) | 1 | (15 | ) | ||||||
| Accumulated other comprehensive income | $ | 129 | $ | 662 | $ | 791 | ||||
| 2014 | ||||||||||
| Opening | Ending | |||||||||
| balance | Net | balance | ||||||||
| (in millions) | January 1 | change | December 31 | |||||||
| Net unrealized foreign currency translation (losses) gains: | ||||||||||
| Unrealized foreign currency translation (losses) gains on net investments in foreign operations | $ | (60 | ) | $ | 333 | $ | 273 | |||
| Losses on hedges of net investments in foreign operations | - | (131 | ) | (131 | ) | |||||
| Income tax recovery | - | 2 | 2 | |||||||
| (60 | ) | 204 | 144 | |||||||
| Cash flow hedges: (Note 31) | ||||||||||
| Net change in fair value of cash flow hedges | - | 1 | 1 | |||||||
| Discontinued cash flow hedges: | ||||||||||
| Net losses on derivative instruments discontinued as cash flow hedges | (1 | ) | 1 | - | ||||||
| Unrealized employee future benefits (losses) gains: (Note 27) | ||||||||||
| Unamortized past service costs | (3 | ) | 1 | (2 | ) | |||||
| Unamortized net actuarial losses | (9 | ) | (11 | ) | (20 | ) | ||||
| Income tax recovery | 1 | 5 | 6 | |||||||
| (11 | ) | (5 | ) | (16 | ) | |||||
| Accumulated other comprehensive (loss) income | $ | (72 | ) | $ | 201 | $ | 129 | |||
22. NON-CONTROLLING INTERESTS
| (in millions) | 2015 | 2014 | ||
| Waneta Partnership | $ | 335 | $ | 316 |
| Caribbean Utilities | 122 | 88 | ||
| Mount Hayes Limited Partnership | 10 | 11 | ||
| Preference shares of Newfoundland Power | 6 | 6 | ||
| $ | 473 | $ | 421 | |
23. STOCK-BASED COMPENSATION PLANS
Stock Options
The Corporation is authorized to grant officers and certain key employees of Fortis and its subsidiaries options to purchase common shares of the Corporation. As at December 31, 2015, the Corporation had the following stock option plans: the 2012 Plan, the 2006 Plan and the 2002 Plan. The 2012 Plan was approved at the May 4, 2012 Annual General Meeting and will ultimately replace the 2002 and 2006 Plans. The 2002 and 2006 Plans will cease to exist when all outstanding options are exercised or expire in or before 2016 and 2018, respectively. The Corporation has ceased the granting of options under the 2002 and 2006 Plans and all new options granted after 2011 are being made under the 2012 Plan. Directors are not eligible to receive grants of options under the 2012 Plan.
Options granted under the 2006 Plan are exercisable for a period not to exceed seven 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.
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.
The following options were granted in 2015 and 2014. The fair values of the options were estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
| 2015 | 2014 | ||||
| March | August | June | February | ||
| Options granted (#) | 667,244 | 12,216 | 23,584 | 925,172 | |
| Exercise price ($) (1) | 39.25 | 33.44 | 32.23 | 30.73 | |
| Grant date fair value ($) | 2.46 | 2.47 | 2.69 | 3.53 | |
| Assumptions: | |||||
| Dividend yield (%) (2) | 3.6 | 3.8 | 3.8 | 3.8 | |
| Expected volatility (%) (3) | 14.6 | 15.7 | 15.9 | 20.3 | |
| Risk-free interest rate (%) (4) | 0.90 | 1.45 | 1.52 | 1.69 | |
| Weighted average expected life (years) (5) | 5.5 | 5.5 | 5.5 | 5.5 | |
| (1) | Five-day VWAP immediately preceding the date of grant |
| (2) | Based on average annual dividend yield up to the date of grant and the weighted average expected life of the options |
| (3) | Based on historical experience over a period equal to the weighted average expected life of the options |
| (4) | Government of Canada benchmark bond yield in effect at the date of grant that covers the weighted average expected life of the options |
| (5) | Based on historical experience |
The Corporation records compensation expense upon the issuance of stock options granted under its 2002, 2006 and 2012 Plans. Using the fair value method, each grant is treated as a single award, the fair value of which is amortized to compensation expense evenly over the four-year vesting period of the options.
The following table summarizes information related to stock options for 2015.
| Total Options | Non-vested Options (1) | |||||
| Weighted | Weighted | |||||
| Average | Average | |||||
| Number of | Exercise | Number of | Grant Date | |||
| Options | Price | Options | Fair Value | |||
| Options outstanding, January 1, 2015 | 4,705,935 | $30.27 | 2,148,380 | $3.84 | ||
| Granted | 667,244 | $39.25 | 667,244 | $2.46 | ||
| Exercised | (885,242 | ) | $27.55 | n/a | n/a | |
| Vested | n/a | n/a | (828,547 | ) | $4.01 | |
| Cancelled/Forfeited | (71,483 | ) | $33.16 | (50,545 | ) | $3.49 |
| Options outstanding, December 31, 2015 | 4,416,454 | $32.12 | 1,936,532 | $3.30 | ||
| Options vested, December 31, 2015 (2) | 2,479,922 | $30.22 | ||||
| (1) | As at December 31, 2015, there was $6 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years. |
| (2) | As at December 31, 2015, the weighted average remaining term of vested options was four years with an aggregate intrinsic value of $18 million. |
The following table summarizes additional 2015 and 2014 stock option information.
| (in millions) | 2015 | 2014 | |||
| Stock option expense recognized | $ | 3 | $ | 3 | |
| Stock options exercised: | |||||
| Cash received for exercise price | 24 | 36 | |||
| Intrinsic value realized by employees | 10 | 12 | |||
| Fair value of options that vested | 3 | 3 | |||
Directors' DSU Plan
Under the Corporation's Directors' DSU Plan, directors who are not officers of the Corporation are eligible for grants of DSUs representing the equity portion of directors' annual compensation. In addition, directors can elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine from time to time that special circumstances exist that would reasonably justify the grant of DSUs to a director as compensation in addition to any regular retainer or fee to which the director is entitled.
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.
| Number of DSUs | 2015 | 2014 | ||
| DSUs outstanding, beginning of year | 176,124 | 203,172 | ||
| Granted | 28,737 | 29,279 | ||
| Granted - notional dividends reinvested | 7,037 | 8,526 | ||
| DSUs paid out | (44,136 | ) | (64,853 | ) |
| DSUs outstanding, end of year | 167,762 | 176,124 |
For the year ended December 31, 2015, expense of $1 million (2014 - $3 million) was recognized in earnings with respect to the DSU Plan.
In 2015, 44,136 DSUs were paid out to retired and deceased directors at a weighted average price of $37.58 per DSU for a total of approximately $2 million.
As at December 31, 2015, the liability related to outstanding DSUs has been recorded at the VWAP of the Corporation's common shares for the last five trading days of 2015 of $37.72, for a total of $6 million (December 31, 2014 - $7 million), and is included in long-term other liabilities (Note 17).
PSU Plans
The Corporation's PSU Plans represent a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries. As at December 31, 2015, the Corporation had the following PSU plans: the 2013 PSU Plan, the 2015 PSU Plan, and certain subsidiaries of the Corporation have also adopted similar share unit plans that are modelled after the Corporation's plans. Each PSU 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 PSUs are subject to a three-year vesting and performance period, at which time a cash payment may be made, as determined by the Human Resources Committee of the Board of Directors. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the VWAP of the Corporation's common shares for five trading days prior to the maturity of the grant and by a payout percentage that may range from 0% to 150%.
The payout percentage for the PSU Plans is based on the Corporation's performance over the three-year period, mainly determined by: (i) the Corporation's total shareholder return as compared to a pre-defined peer group of companies; and (ii) the Corporation's cumulative compound annual growth rate in earnings per common share or, for certain subsidiaries, the Company's cumulative net income, as compared to the target established at the time of the grant. As at December 31, 2015, the estimated payout percentages for the grants under the 2013 and 2015 PSU Plans range from 96% to 118%.
The following table summarizes information related to the PSUs for 2015 and 2014.
| Number of PSUs | 2015 | 2014 | ||
| PSUs outstanding, beginning of year | 481,700 | 257,419 | ||
| Granted | 276,381 | 261,737 | ||
| Granted - notional dividends reinvested | 25,687 | 17,691 | ||
| PSUs paid out | (83,637 | ) | (33,559 | ) |
| PSUs cancelled/forfeited | (5,745 | ) | (21,588 | ) |
| PSUs outstanding, end of year | 694,386 | 481,700 |
In January 2015, 68,759 PSUs were paid out to the former Chief Executive Officer ("CEO") of the Corporation at $38.90 per PSU, for a total of approximately $3 million. The payout was made in respect of the PSU grant made in March 2012 and the former CEO satisfying the payment requirements, as determined by the Human Resources Committee of the Board of Directors. As a result of the sale of commercial real estate and hotel assets, in October 2015 14,878 PSUs were paid out to certain employees at a 100% payout percentage under the 2013 PSU Plan and the 2015 PSU Plan at $38.48 per PSU, for a total of approximately $1 million.
For the year ended December 31, 2015, expense of approximately $12 million (2014 - $7 million) was recognized in earnings with respect to the PSU Plans and there was $9 million of unrecognized compensation expense related to PSUs not yet vested, which is expected to be recognized over a weighted average period of approximately two years.
As at December 31, 2015, the aggregate intrinsic value of the outstanding PSUs was $28 million, with a weighted average contractual life of approximately one year. The liability related to outstanding PSUs has been recorded at the VWAP of the Corporation's common shares for the last five trading days of 2015 of $37.72, for a total of $19 million (December 31, 2014 - $10 million), and is included in accounts payable and other current liabilities and long-term other liabilities (Notes 14 and 17).
RSU Plans
In February 2015 the Corporation's Board of Directors approved the 2015 RSU Plan, effective January 1, 2015. The Corporation's 2015 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.
| Number of RSUs | 2015 | |
| Granted | 59,462 | |
| Granted - notional dividends reinvested | 2,150 | |
| RSUs cancelled/forfeited | (2,872 | ) |
| RSUs outstanding, end of year | 58,740 |
For the year ended December 31, 2015, expense of approximately $1 million was recognized in earnings with respect to the RSU Plan and there was approximately $1 million of unrecognized compensation expense related to RSUs not yet vested, which is expected to be recognized over a weighted average period of approximately two years.
As at December 31, 2015, the liability related to outstanding RSUs was recorded at the VWAP of the Corporation's common shares for the last five trading days of 2015 of $37.72, for a total of $1 million, and is included in long-term other liabilities (Note 17).
24. OTHER INCOME (EXPENSES), NET
| (in millions) | 2015 | 2014 | ||||
| Net gain on sale of commercial real estate and hotel assets (Note 28) (1) | $ | 109 | $ | - | ||
| Gain on sale of non-regulated generation assets (Note 28) (2) | 56 | - | ||||
| Equity component of AFUDC | 23 | 11 | ||||
| Net foreign exchange gain | 13 | 8 | ||||
| Interest income | 8 | 13 | ||||
| Loss on settlement of expropriation matters (Note 9) | (9 | ) | - | |||
| Acquisition-related expenses (Notes 29 and 35) | (10 | ) | (25 | ) | ||
| Acquisition-related customer and | ||||||
| community benefits (Notes 8 (xvii) and 29) | - | (33 | ) | |||
| Other | (3 | ) | 1 | |||
| $ | 187 | $ | (25 | ) |
| (1) | Net of $23 million of expenses associated with the sale |
| (2) | Net of $6 million of expenses and foreign exchange impacts associated with the sale |
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 (Note 9). As a result of the settlement, the Corporation recognized an approximate $9 million loss in 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.
The acquisition-related expenses and customer and community benefits in 2014 were associated with the acquisition of UNS Energy (Note 29).
25. FINANCE CHARGES
| (in millions) | 2015 | 2014 | |||||
| Interest | - Long-term debt and capital lease and finance obligations | $ | 572 | $ | 482 | ||
| - Short-term borrowings | 8 | 20 | |||||
| - Convertible Debentures (Note 18) | - | 72 | |||||
| Debt component of AFUDC | (27 | ) | (27 | ) | |||
| $ | 553 | $ | 547 | ||||
26. INCOME TAXES
Deferred Income Taxes
Deferred income taxes are provided for temporary differences. The significant components of deferred income tax assets and liabilities consist of the following.
| (in millions) | 2015 | 2014 | ||||
| Gross deferred income tax assets | ||||||
| Tax loss and credit carryforwards | $ | 387 | $ | 376 | ||
| Regulatory liabilities | 210 | 186 | ||||
| Employee future benefits | 116 | 108 | ||||
| Share issue and debt financing costs | 13 | 20 | ||||
| Unrealized foreign exchange losses on long-term debt | 65 | 17 | ||||
| Other | 45 | 70 | ||||
| 836 | 777 | |||||
| Deferred income tax assets valuation allowance | (73 | ) | (24 | ) | ||
| Net deferred income tax assets | $ | 763 | $ | 753 | ||
| Gross deferred income tax liabilities | ||||||
| Utility capital assets | $ | (2,575 | ) | $ | (2,096 | ) |
| Regulatory assets | (201 | ) | (204 | ) | ||
| Non-utility capital assets | - | (40 | ) | |||
| Intangible assets | (37 | ) | (39 | ) | ||
| (2,813 | ) | (2,379 | ) | |||
| Net deferred income tax liability | $ | (2,050 | ) | $ | (1,626 | ) |
The deferred income tax asset associated with unrealized foreign exchange losses on long-term debt reflects $65 million of capital losses as at December 31, 2015 (December 31, 2014 - $17 million). The deferred income tax asset can only be used if the Corporation has capital gains to offset the losses. Management believes that it is more likely than not that Fortis will not be able to generate future capital gains and, as a result, the Corporation recorded a $65 million valuation allowance against the deferred income tax asset as at December 31, 2015 (December 31, 2014 - $17 million). Management believes that based on its historical pattern of taxable income, Fortis will produce sufficient income in the future to realize all other deferred income tax assets.
Unrecognized Tax Benefits
The following table summarizes the change in unrecognized tax benefits during 2015 and 2014.
| (in millions) | 2015 | 2014 | ||
| Total unrecognized tax benefits, beginning of year | $ | 11 | $ | 3 |
| Additions related to the current year | 1 | 7 | ||
| Adjustments related to prior years | 1 | 1 | ||
| Total unrecognized tax benefits, end of year | $ | 13 | $ | 11 |
Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2015. Fortis has not recognized interest expense in 2015 and 2014 related to unrecognized tax benefits.
The components of the income tax expense were as follows.
| (in millions) | 2015 | 2014 | |||||
| Canadian | |||||||
| Current income taxes | $ | 59 | $ | 43 | |||
| Deferred income taxes | 113 | 64 | |||||
| Less: regulatory adjustments | (100 | ) | (67 | ) | |||
| 13 | (3 | ) | |||||
| Total Canadian | $ | 72 | $ | 40 | |||
| Foreign | |||||||
| Deferred income taxes | 151 | 26 | |||||
| Total Foreign | $ | 151 | $ | 26 | |||
| Income tax expense | $ | 223 | $ | 66 | |||
Income taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income taxes. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
| (in millions, except as noted) | 2015 | 2014 | ||||
| Combined Canadian federal and provincial statutory income tax rate | 27.5 | % | 29.0 | % | ||
| Statutory income tax rate applied to earnings before income taxes | $ | 292 | $ | 131 | ||
| Difference between Canadian statutory income tax rate and rates applicable to foreign subsidiaries | (7 | ) | (23 | ) | ||
| Difference in Canadian provincial statutory income tax rates applicable to subsidiaries in different Canadian jurisdictions | (4 | ) | (10 | ) | ||
| Items capitalized for accounting purposes but expensed for income tax purposes | (39 | ) | (26 | ) | ||
| Difference between gain on sale of assets for accounting and amounts calculated for tax purposes | (18 | ) | - | |||
| Change in tax rates and legislation | 13 | - | ||||
| Other | (14 | ) | (6 | ) | ||
| Income tax expense | $ | 223 | $ | 66 | ||
| Effective tax rate | 21.0 | % | 14.6 | % | ||
In 2015 the Corporation's combined Canadian federal and provincial statutory income tax rate decreased from 29.0% to 27.5%. This change resulted from the inclusion of the Waneta Partnership's taxable income, which is taxable in the province of British Columbia at a lower provincial income tax rate, and increased income tax expense by approximately $3 million in 2015, through the re-measurement of deferred income tax assets. In addition, a change in New York State tax legislation in 2015 resulted in the need to include UNS Energy as part of the combined New York State tax return. As a result, existing deferred income tax balances were adjusted to reflect the effect of the change in the tax law, resulting in an increase in income tax expense of approximately $10 million in 2015.
As at December 31, 2015, the Corporation had the following tax carryforward amounts.
| (in millions) | Expiring Year | Amount | ||
| Canadian | ||||
| Capital loss | N/A | $ | 15 | |
| Non-capital loss | 2025-2035 | 129 | ||
| Other tax credits | 2026-2035 | 2 | ||
| 146 | ||||
| Unrecognized in the consolidated financial statements | (15 | ) | ||
| $ | 131 | |||
| Foreign | ||||
| Capital loss | 2017 | $ | 12 | |
| Federal and state net operating loss | 2031-2034 | 653 | ||
| Other tax credits | 2016-2035 | 69 | ||
| Alternative minimum tax credits | N/A | 64 | ||
| 798 | ||||
| Unrecognized in the consolidated financial statements | (17 | ) | ||
| 781 | ||||
| Total tax carryforwards | $ | 912 | ||
As at December 31, 2015, the Corporation had approximately $912 million in tax carryforward amounts recognized in the consolidated financial statements (December 31, 2014 - $1,093 million).
The Corporation and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential examinations include the United States (Federal, Arizona and New York) and Canada (Federal and British Columbia). The Corporation's 2010 to 2015 taxation years are still open for audit in the Canadian jurisdictions and 2011 to 2015 taxation years are still open for audit in the United States jurisdictions. The Corporation is not currently under examination for income tax matters in any of these jurisdictions.
27. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, defined contribution pension plans, and OPEB plans. For the defined benefit pension and OPEB plan arrangements, the benefit obligation and the fair value of plan assets are measured for accounting purposes as at December 31 of each year.
Actuarial valuations are required to determine funding contributions for pension plans, at least, every three years for Fortis' Canadian and Caribbean subsidiaries. The most recent valuations were as of December 31, 2012 for FortisBC Energy (plan covering non-unionized employees), FortisAlberta and Caribbean Utilities; December 31, 2013 for FortisBC Electric and FortisBC Energy (plans covering unionized employees); as of December 31, 2014 for Newfoundland Power, FortisOntario, and the Corporation.
UNS Energy and Central Hudson perform annual actuarial valuations, as their funding contribution requirements are based on maintaining annual target fund percentages. Both UNS Energy and Central Hudson have met the minimum funding requirements.
The Corporation's investment policy is to ensure that the defined benefit pension and OPEB plan assets, together with expected contributions, are invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans for its members. The investment objective of the defined benefit pension and OPEB plans is to maximize return in order to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and defined benefit pension and OPEB expense for consolidated financial statement purposes.
The Corporation's consolidated defined benefit pension and OPEB plan weighted average asset allocations were as follows.
| Plan assets as at December 31 | 2015 Target | ||
| (%) | Allocation | 2015 | 2014 |
| Equities | 50 | 51 | 49 |
| Fixed income | 46 | 44 | 46 |
| Real estate | 4 | 4 | 4 |
| Cash and other | - | 1 | 1 |
| 100 | 100 | 100 |
The fair value measurements of defined benefit pension and OPEB plan assets by fair value hierarchy, as defined in Note 31, were as follows.
| Fair value of plan assets as at December 31, 2015 | ||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Total | ||||
| Equities | $ | 417 | $ | 922 | $ | - | $ | 1,339 |
| Fixed income | - | 1,166 | - | 1,166 | ||||
| Real estate | - | 14 | 97 | 111 | ||||
| Private equities | - | - | 10 | 10 | ||||
| Cash and other | 3 | 18 | - | 21 | ||||
| $ | 420 | $ | 2,120 | $ | 107 | $ | 2,647 | |
| Fair value of plan assets as at December 31, 2014 | ||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Total | ||||
| Equities | $ | 352 | $ | 806 | $ | - | $ | 1,158 |
| Fixed income | 23 | 1,069 | - | 1,092 | ||||
| Real estate | - | 11 | 85 | 96 | ||||
| Private equities | - | - | 8 | 8 | ||||
| Cash and other | 6 | 10 | - | 16 | ||||
| $ | 381 | $ | 1,896 | $ | 93 | $ | 2,370 | |
The following table is a reconciliation of changes in the fair value of pension plan assets that have been measured using Level 3 inputs for the years ended December 31, 2015 and 2014.
| (in millions) | 2015 | 2014 | ||
| Balance, beginning of year | $ | 93 | $ | 62 |
| Assets assumed on acquisition | - | 24 | ||
| Actual return on plan assets held at end of year | 9 | 6 | ||
| Foreign currency translation impacts | 5 | - | ||
| Purchases, sales and settlements | - | 1 | ||
| Balance, end of year | $ | 107 | $ | 93 |
The following is a breakdown of the Corporation's and subsidiaries' defined benefit pension and OPEB plans and their respective funded status.
| Defined Benefit | ||||||||||||
| Pension Plans | OPEB Plans | |||||||||||
| (in millions) | 2015 | 2014 | 2015 | 2014 | ||||||||
| Change in benefit obligation (1) | ||||||||||||
| Balance, beginning of year | $ | 2,604 | $ | 1,724 | $ | 564 | $ | 417 | ||||
| Liabilities assumed on acquisition | - | 403 | - | 83 | ||||||||
| Service costs | 68 | 43 | 17 | 11 | ||||||||
| Employee contributions | 17 | 17 | 1 | 1 | ||||||||
| Interest costs | 109 | 90 | 23 | 21 | ||||||||
| Benefits paid | (118 | ) | (101 | ) | (21 | ) | (15 | ) | ||||
| Actuarial (gains) losses | (102 | ) | 335 | (50 | ) | 27 | ||||||
| Past service credits/plan amendments | - | - | (10 | ) | - | |||||||
| Foreign currency translation impacts | 250 | 93 | 50 | 19 | ||||||||
| Balance, end of year (2) | $ | 2,828 | $ | 2,604 | $ | 574 | $ | 564 | ||||
| Change in value of plan assets | ||||||||||||
| Balance, beginning of year | $ | 2,216 | $ | 1,541 | $ | 154 | $ | 121 | ||||
| Assets assumed on acquisition | - | 373 | - | 13 | ||||||||
| Actual return on plan assets | 30 | 236 | - | 11 | ||||||||
| Benefits paid | (118 | ) | (101 | ) | (21 | ) | (15 | ) | ||||
| Employee contributions | 17 | 17 | 1 | 1 | ||||||||
| Employer contributions | 99 | 70 | 17 | 11 | ||||||||
| Foreign currency translation impacts | 222 | 80 | 30 | 12 | ||||||||
| Balance, end of year | $ | 2,466 | $ | 2,216 | $ | 181 | $ | 154 | ||||
| Funded status | $ | (362 | ) | $ | (388 | ) | $ | (393 | ) | $ | (410 | ) |
| (1) | Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans |
| (2) | The accumulated benefit obligation for defined benefit pension plans, excluding assumptions about future salary levels, was $2,595 million as at December 31, 2015 (December 31, 2014 - $2,378 million). |
The following table summarizes the employee future benefit assets and liabilities and their classifications on the consolidated balance sheet.
| Defined Benefit | |||||||||
| Pension Plans | OPEB Plans | ||||||||
| (in millions) | 2015 | 2014 | 2015 | 2014 | |||||
| Assets | |||||||||
| Defined benefit pension assets: | |||||||||
| Long-term other assets | $ | 11 | $ | 6 | $ | - | $ | - | |
| Liabilities | |||||||||
| Defined benefit pension liabilities: | |||||||||
| Current (Note 14) | 5 | 4 | - | - | |||||
| Long-term other liabilities (Note 17) | 368 | 390 | - | - | |||||
| OPEB plan liabilities: | |||||||||
| Current (Note 14) | - | - | 8 | 7 | |||||
| Long-term other liabilities (Note 17) | - | - | 385 | 403 | |||||
| Net liabilities | $ | 362 | $ | 388 | $ | 393 | $ | 410 | |
The net benefit cost for the Corporation's defined benefit pension plans and OPEB plans were as follows:
| Defined Benefit | ||||||||||||
| Pension Plans | OPEB Plans | |||||||||||
| (in millions) | 2015 | 2014 | 2015 | 2014 | ||||||||
| Components of net benefit cost | ||||||||||||
| Service costs | $ | 68 | $ | 43 | $ | 17 | $ | 11 | ||||
| Interest costs | 109 | 90 | 23 | 21 | ||||||||
| Expected return on plan assets | (140 | ) | (106 | ) | (12 | ) | (9 | ) | ||||
| Amortization of actuarial losses | 57 | 32 | 5 | 3 | ||||||||
| Amortization of past service credits/plan amendments | - | (1 | ) | (5 | ) | (3 | ) | |||||
| Amortization of transitional obligation (asset) | 2 | 2 | (7 | ) | (6 | ) | ||||||
| Regulatory adjustments | 1 | 11 | 6 | 4 | ||||||||
| Net benefit cost | $ | 97 | $ | 71 | $ | 27 | $ | 21 | ||||
The following tables provide the components of accumulated other comprehensive loss and regulatory assets and liabilities, which would otherwise have been recognized as accumulated other comprehensive loss, for the years ended December 31, 2015 and 2014 that have not been recognized as components of net benefit cost.
| Defined Benefit | ||||||||||||
| Pension Plans | OPEB Plans | |||||||||||
| (in millions) | 2015 | 2014 | 2015 | 2014 | ||||||||
| Unamortized net actuarial losses | $ | 16 | $ | 16 | $ | 4 | $ | 4 | ||||
| Unamortized past service costs | 1 | - | - | 2 | ||||||||
| Income tax recovery | (5 | ) | (5 | ) | (1 | ) | (1 | ) | ||||
| Accumulated other comprehensive loss (Note 21) | $ | 12 | $ | 11 | $ | 3 | $ | 5 | ||||
| Net actuarial losses | $ | 513 | $ | 513 | $ | 41 | $ | 95 | ||||
| Past service credits | - | - | (33 | ) | (43 | ) | ||||||
| Amount deferred due to actions of regulators | 23 | 18 | 39 | 39 | ||||||||
| $ | 536 | $ | 531 | $ | 47 | $ | 91 | |||||
| Regulatory assets (Note 8 (ii)) | $ | 536 | $ | 531 | $ | 91 | $ | 149 | ||||
| Regulatory liabilities (Note 8 (ii)) | - | - | (44 | ) | (58 | ) | ||||||
| Net regulatory assets | $ | 536 | $ | 531 | $ | 47 | $ | 91 | ||||
The following tables provide the components recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income.
| Defined Benefit | ||||||||||||
| Pension Plans | OPEB Plans | |||||||||||
| (in millions) | 2015 | 2014 | 2015 | 2014 | ||||||||
| Current year net actuarial losses (gains) | $ | - | $ | 9 | $ | (1 | ) | $ | 3 | |||
| Past service credits/plan amendments | - | - | (1 | ) | (1 | ) | ||||||
| Amortization of actuarial gains (losses) | 1 | (1 | ) | - | - | |||||||
| Income tax recovery | - | (4 | ) | - | (1 | ) | ||||||
| Total recognized in comprehensive income | $ | 1 | $ | 4 | $ | (2 | ) | $ | 1 | |||
| Assets assumed on acquisition | $ | - | $ | 79 | $ | - | $ | 6 | ||||
| Current year net actuarial losses (gains) | 8 | 197 | (28 | ) | 23 | |||||||
| Past service credits/plan amendments | - | - | (10 | ) | - | |||||||
| Amortization of actuarial losses | (56 | ) | (31 | ) | (5 | ) | (5 | ) | ||||
| Amortization of past service costs | (1 | ) | (1 | ) | (2 | ) | (3 | ) | ||||
| Foreign currency translation impacts | 49 | 14 | (6 | ) | (4 | ) | ||||||
| Regulatory adjustments | 5 | (37 | ) | 7 | (1 | ) | ||||||
| Total recognized in regulatory assets | $ | 5 | $ | 221 | $ | (44 | ) | $ | 16 | |||
Net actuarial losses of $1 million are expected to be amortized from accumulated other comprehensive income into net benefit cost in 2016 related to defined benefit pension plans.
Net actuarial losses of $47 million, past service credits of $1 million and regulatory adjustments of $2 million are expected to be amortized from regulatory assets into net benefit cost in 2016 related to defined benefit pension plans. Net actuarial losses of $3 million, past service credits of $1 million and regulatory adjustments of $5 million are expected to be amortized from regulatory assets into net benefit cost in 2016 related to OPEB plans.
| Significant weighted average assumptions | Defined Benefit Pension Plans | OPEB Plans | ||
| % | 2015 | 2014 | 2015 | 2014 |
| Discount rate during the year | 4.00 | 4.81 | 3.95 | 4.72 |
| Discount rate as at December 31 | 4.21 | 4.00 | 4.12 | 3.95 |
| Expected long-term rate of return on plan assets (1) | 6.25 | 6.46 | 6.95 | 7.08 |
| Rate of compensation increase | 3.48 | 3.48 | - | - |
| Health care cost trend increase as at December 31 (2) | - | - | 4.67 | 4.67 |
| (1) | Developed by management with assistance from independent actuaries using best estimates of expected returns, volatilities and correlations for each class of asset. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. |
| (2) | The projected 2016 weighted average health care cost trend rate is 6.98% for OPEB plans and is assumed to decrease over the next 13 years by 2028 to the weighted average ultimate health care cost trend rate of 4.67% and remain at that level thereafter. |
For 2015 the effects of changing the health care cost trend rate by 1% were as follows.
| 1% increase | 1% decrease | |||
| (in millions) | in rate | in rate | ||
| Increase (decrease) in accumulated benefit obligation | $ | 51 | $ | (43) |
| Increase (decrease) in service and interest costs | 5 | (3) |
The following table provides the amount of benefit payments expected to be made over the next 10 years.
| Defined Benefit | ||||
| Pension Payments | OPEB Payments | |||
| Year | (in millions) | (in millions) | ||
| 2016 | $ | 122 | $ | 24 |
| 2017 | 127 | 26 | ||
| 2018 | 131 | 27 | ||
| 2019 | 136 | 29 | ||
| 2020 | 141 | 30 | ||
| 2021 - 2025 | 796 | 173 |
Refer to Note 33 for expected defined benefit pension and OPEB plan funding contributions.
During 2015 the Corporation expensed $28 million (2014 - $21 million) related to defined contribution pension plans.
28. DISPOSITIONS AND DISCONTINUED OPERATIONS
Sale of Commercial Real Estate and Hotel Assets
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 (Note 24). As part of the transaction, Fortis subscribed to $35 million in trust units of Slate Office REIT in conjunction with the REIT's public offering (Notes 9 and 31).
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 reflects an impairment loss and expenses associated with the sale transaction (Note 24).
Net proceeds from the sales were used by the Corporation to repay credit facility borrowings, the majority of which were used to finance a portion of the acquisition of UNS Energy (Note 29), and for other general corporate purposes.
Earnings before taxes related to Fortis Properties of approximately $18 million were recognized in 2015, excluding the net gain on sale, compared to $31 million in 2014.
Sale of Non-Regulated Generation Assets in New York and Ontario
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 (Note 24).
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) (Note 24).
Earnings before taxes of less than $1 million were recognized in 2015, excluding the gain on sale, compared to $3 million in 2014.
Sale of Griffith
In March 2014 Griffith was sold for proceeds of approximately $105 million (US$95 million). The results of operations to the date of sale are presented as discontinued operations on the consolidated statements of earnings. As a result of the disposal, earnings from discontinued operations of $8 million ($5 million after tax) were recognized in the first quarter of 2014.
29. BUSINESS ACQUISITIONS
2015
PENDING ACQUISITION OF AITKEN CREEK GAS STORAGE FACILITY
In December 2015 Fortis, through an indirect wholly owned subsidiary, entered into a definitive share purchase and sale agreement with Chevron Canada Properties Ltd. to acquire its shares of the Aitken Creek Gas Storage Facility ("Aitken Creek") for approximately US$266 million, subject to customary closing conditions and adjustments. Aitken Creek is the largest gas storage facility in British Columbia with a total working gas capacity of 77 billion cubic feet and is an integral part of Western Canada's natural gas transmission network. The acquisition is subject to regulatory approval and is expected to close in the first half of 2016. The net cash purchase price is expected to be initially financed with borrowings under the Corporation's credit facility. In December 2015 the Corporation paid a deposit of US$29 million related to the transaction, which is included in long-term other assets on the consolidated balance sheet (Note 9).
2014
UNS ENERGY
On August 15, 2014, Fortis acquired all of the outstanding common shares of UNS Energy for US$60.25 per common share in cash, for an aggregate purchase price of approximately US$4.5 billion, including the assumption of US$2.0 billion of debt on closing.
Financing of the net cash purchase price of approximately $2.7 billion (US$2.5 billion) is complete. Fortis completed the sale of $1.8 billion 4% Convertible Debentures. Proceeds from the first installment of approximately $599 million were received in January 2014. A significant portion of these cash proceeds were used to finance a portion of the UNS Energy acquisition. Proceeds from the final installment of approximately $1.2 billion were received on October 28, 2014 and were used to repay borrowings under acquisition credit facilities initially used to finance a portion of the UNS Energy acquisition. Substantially all of the Convertible Debentures have been converted into approximately 58.6 million common shares of Fortis (Note 18). In September 2014 Fortis issued 24 million 4.1% Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series M for gross proceeds of $600 million (Note 20). The net proceeds were also used to repay a portion of borrowings under the acquisition credit facilities. The remainder of the purchase price was financed through credit facility borrowings under a medium-term bridge facility and the Corporation's revolving credit facility (Note 32), which were subsequently repaid using net proceeds from the sale of commercial real estate and hotel assets (Note 28).
UNS Energy's operations are regulated by the ACC and FERC (Note 2). The determination of revenue and earnings is based on a regulated rate of return that is applied to historic values, which do not change with a change of ownership. No fair value adjustments, other than goodwill, were recorded for the net assets acquired because all of the economic benefits and obligations associated with them beyond regulated rates of return accrue to the customers.
The following table summarizes the final allocation of the purchase consideration to the assets and liabilities acquired as at August 15, 2014, based on their fair values, using an exchange rate of US$1.00=CAD$1.0925.
| (in millions) | Total | ||
| Purchase consideration | $ | 2,745 | |
| Fair value assigned to net assets: | |||
| Current assets | 539 | ||
| Long-term regulatory assets | 185 | ||
| Utility capital assets | 3,972 | ||
| Intangible assets | 116 | ||
| Other long-term assets | 108 | ||
| Current liabilities | (458 | ) | |
| Assumed long-term debt and capital lease and finance obligations (including current portion) | (2,186 | ) | |
| Long-term regulatory liabilities | (341 | ) | |
| Other long-term liabilities | (797 | ) | |
| 1,138 | |||
| Cash and cash equivalents | 97 | ||
| Fair value of net assets acquired | 1,235 | ||
| Goodwill (Note 13) | $ | 1,510 | |
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 August 15, 2014.
In 2014 acquisition-related expenses of approximately $25 million ($19 million after tax) were recognized in other income (expenses), net on the consolidated statement of earnings (Note 24). In addition, approximately $33 million (US$30 million), or $20 million (US$18 million) after tax, in customer benefits offered to obtain regulatory approval of the acquisition were expensed in 2014 and were also recognized in other income (expenses), net on the consolidated statement of earnings (Notes 8 (xvii) and 24).
30. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| (in millions) | 2015 | 2014 | ||||
| Cash paid for: | ||||||
| Interest | $ | 561 | $ | 538 | ||
| Income taxes | 109 | 83 | ||||
| Change in non-cash operating working capital: | ||||||
| Accounts receivable and other current assets | $ | 14 | $ | 53 | ||
| Prepaid expenses | (1 | ) | 2 | |||
| Inventories | 15 | (11 | ) | |||
| Regulatory assets - current portion | 57 | (16 | ) | |||
| Accounts payable and other current liabilities | (82 | ) | (123 | ) | ||
| Regulatory liabilities - current portion | 38 | (29 | ) | |||
| $ | 41 | $ | (124 | ) | ||
| Non-cash investing and financing activities: | ||||||
| Common share dividends reinvested | $ | 156 | $ | 81 | ||
| Conversion of Convertible Debentures into common shares (Note 18) | 1 | 1,747 | ||||
| Additions to utility capital assets, non-utility capital assets, and intangible assets included in current and long-term liabilities | 187 | 200 | ||||
| Contributions in aid of construction included in current assets | 4 | 7 | ||||
| Exercise of stock options into common shares | 4 | 5 | ||||
31. 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.
| Fair value | As at December 31 | ||||||
| (in millions) | hierarchy | 2015 | 2014 | ||||
| Assets | |||||||
| Energy contracts subject to regulatory deferral (1) (2) (3) | Levels 2/3 | $ | 7 | $ | 3 | ||
| Energy contracts not subject to regulatory deferral (1) (2) | Level 3 | 2 | 1 | ||||
| Available-for-sale investment (Note 9) (4) (5) | Level 1 | 33 | - | ||||
| Assets held for sale (Note 6) | Level 2 | 9 | - | ||||
| Other investments (4) | Level 1 | 12 | 5 | ||||
| Total gross assets | 63 | 9 | |||||
| Less: Counterparty netting not offset on the balance sheet (6) | (6 | ) | (3 | ) | |||
| Total net assets | $ | 57 | $ | 6 | |||
| Liabilities | |||||||
| Energy contracts subject to regulatory deferral (1) (2) (7) | Levels 1/2/3 | $ | 78 | $ | 72 | ||
| Energy contracts not subject to regulatory deferral (1) (2) | Level 3 | - | 1 | ||||
| Energy contracts - cash flow hedges (2) (8) | Level 3 | - | 1 | ||||
| Interest rate swaps - cash flow hedges (8) | Level 2 | 5 | 5 | ||||
| Total gross liabilities | 83 | 79 | |||||
| Less: Counterparty netting not offset on the balance sheet (6) | (6 | ) | (3 | ) | |||
| Total net liabilities | $ | 77 | $ | 76 | |||
| (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 rates as permitted by the regulators, with the exception of long-term wholesale trading contracts. |
| (2) | Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term wholesale trading contracts and those that qualify as cash flow hedges. |
| (3) | Includes $2 million - level 2 and $5 million - level 3 (2014 - $3 million - level 3) |
| (4) | Included in long-term other assets on the consolidated balance sheet |
| (5) | The cost of the available-for-sale investment was $35 million 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 (Notes 9 and 28). |
| (6) | 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. |
| (7) | Includes $1 million - level 1, $52 million - level 2 and $25 million - level 3 (2014 - $2 million - level 1, $35 million - level 2 and $35 million - level 3) |
| (8) | The fair value of certain of the Corporation's energy contracts are recorded in accounts payable and other current liabilities and the fair value of the Corporation's interest rate swaps are recorded in accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value are recorded in other comprehensive income until they become realized and are reclassified to earnings. |
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts and gas swap and option contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships and transmission and line losses. The fair value of gas option contracts is estimated using a Black-Scholes option-pricing model, which includes inputs such as implied volatility, interest rates, and forward price curves. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
Central Hudson holds electricity swap contracts and gas swap and option contracts to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair value of the electricity swap contracts and gas swap and option contracts was calculated using forward pricing provided by independent third parties.
FortisBC Energy holds gas purchase 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 December 31, 2015, 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 December 31, 2015, unrealized losses of $74 million (December 31, 2014 - $69 million) were recognized in regulatory assets and unrealized gains of $3 million were recognized in regulatory liabilities (Note 8 (vii)).
Energy Contracts Not Subject to Regulatory Deferral
In June 2015 UNS Energy entered into long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with the ratepayer through UNS Energy's rate stabilization accounts.
Cash Flow Hedges
UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on lease debt, and held a power purchase swap, that expired in September 2015, to hedge the cash flow risk associated with a long-term power supply agreement. The after-tax unrealized gains and losses on cash flow hedges are recorded in other comprehensive income and reclassified to earnings as they become realized. The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $1 million.
Central Hudson holds interest rate cap contracts expiring in 2016 and 2017 on bonds with a total principal amount of US$64 million. Variations in the interest costs of the bonds, including any gains or losses associated with the interest rate cap contracts, are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator and do not impact earnings.
Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.
Volume of Derivative Activity
As at December 31, 2015, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.
| Maturity | Contracts | There- | |||||||
| Volume | (year) | (#) | 2016 | 2017 | 2018 | 2019 | 2020 | after | |
| Energy contracts subject to regulatory deferral: | |||||||||
| Electricity swap contracts (gigawatt hours ("GWh")) | 2019 | 8 | 1,043 | 730 | 438 | 219 | - | - | |
| Electricity power purchase contracts (GWh) | 2017 | 28 | 1,027 | 145 | - | - | - | - | |
| Gas swap and option contracts (petajoules ("PJ")) | 2018 | 154 | 40 | 10 | 4 | - | - | - | |
| Gas purchase contract premiums (PJ) | 2024 | 89 | 91 | 42 | 38 | 22 | 22 | 64 | |
| Energy contracts not subject to regulatory deferral: | |||||||||
| Long-term wholesale trading contracts (GWh) | 2016 | 6 | 1,310 | - | - | - | - | - | |
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 | ||||||||||||
| Asset (Liability) | December 31, 2015 | December 31, 2014 | ||||||||||
| Carrying | Estimated | Carrying | Estimated | |||||||||
| (in millions) | Value | Fair Value | Value | Fair Value | ||||||||
| Long-term other asset - Belize Electricity (1) | $ | - | $ | - | $ | 116 | $ | n/a | ||||
| Long-term debt, including current portion (Note 15) (2) | (11,240 | ) | (12,614 | ) | (10,501 | ) | (12,237 | ) | ||||
| Waneta Partnership promissory note (Note 17) | (56 | ) | (59 | ) | (53 | ) | (56 | ) | ||||
| (1) | In August 2015 the Corporation settled expropriation matters with the GOB regarding the GOB's expropriation of Belize Electricity (Note 9). |
| (2) | The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $551 million (December 31, 2014 - $1,096 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs. |
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.
32. 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 December 31, 2015, FortisAlberta's gross credit risk exposure was approximately $116 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $3 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
UNS Energy, Central Hudson and FortisBC Energy may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by only dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.
To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at December 31, 2015, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $260 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at December 31, 2015, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.6 billion, of which approximately $2.4 billion was unused, including $570 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, as well as large banks in the United States, with no one bank holding more than 20% of these facilities. Approximately $3.3 billion of the total credit facilities are committed facilities with maturities ranging from 2016 through 2020.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| Total as at | Total as at | ||||||||||||
| Regulated | Corporate | December 31, | December 31, | ||||||||||
| (in millions) | Utilities | and Other | 2015 | 2014 | |||||||||
| Total credit facilities (1) | $ | 2,211 | $ | 1,354 | $ | 3,565 | $ | 3,854 | |||||
| Credit facilities utilized: | |||||||||||||
| Short-term borrowings (2) | (511 | ) | - | (511 | ) | (330 | ) | ||||||
| Long-term debt (Note 15) (3) | (71 | ) | (480 | ) | (551 | ) | (1,096 | ) | |||||
| Letters of credit outstanding | (68 | ) | (36 | ) | (104 | ) | (192 | ) | |||||
| Credit facilities unused | $ | 1,561 | $ | 838 | $ | 2,399 | $ | 2,236 | |||||
| (1) | Total credit facilities exclude a $300 million option to increase the Corporation's committed corporate credit facility, as discussed below. |
| (2) | The weighted average interest rate on short-term borrowings was approximately 1.0% as at December 31, 2015 (December 31, 2014 - 1.3%). |
| (3) | As at December 31, 2015, credit facility borrowings classified as long-term debt included $71 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2014 - $257 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 1.5% as at December 31, 2015 (December 31, 2014 - 1.8%). |
As at December 31, 2015 and 2014, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods.
Regulated Utilities
The UNS Utilities have a total of US$350 million ($484 million) in unsecured committed revolving credit facilities maturing in October 2020, with the option of two one-year extensions.
Central Hudson has a US$200 million ($277 million) unsecured committed revolving credit facility, maturing in October 2020, that is utilized to finance capital expenditures and for general corporate purposes. Central Hudson also has an uncommitted credit facility totalling US$25 million ($34 million).
FEI has a $700 million unsecured committed revolving credit facility, maturing in August 2018, that is utilized to finance working capital requirements, capital expenditures and for general corporate purposes.
FortisAlberta has a $250 million unsecured committed revolving credit facility, maturing in August 2020, that is utilized to finance capital expenditures and for general corporate purposes.
FortisBC Electric has a $150 million unsecured committed revolving credit facility, maturing in May 2018. This facility is utilized to finance capital expenditures and for general corporate purposes. FortisBC Electric also has a $10 million unsecured demand overdraft facility.
Newfoundland Power has a $100 million unsecured committed revolving credit facility, maturing in August 2019, and a $20 million demand credit facility. Maritime Electric has a $50 million unsecured committed revolving credit facility, maturing in February 2019, and a $5 million unsecured demand credit facility. FortisOntario has a $30 million unsecured committed revolving credit facility, maturing in June 2016.
Caribbean Utilities has unsecured credit facilities totalling approximately US$47 million ($65 million). Fortis Turks and Caicos has short-term unsecured demand credit facilities of US$26 million ($36 million), maturing in September 2016.
Corporate and Other
Fortis has a $1 billion unsecured committed revolving credit facility, maturing in July 2020, that is available for general corporate purposes. The Corporation has the ability to increase this facility to $1.3 billion. As at December 31, 2015, the Corporation has not yet exercised its option for the additional $300 million. The Corporation also has a $35 million letter of credit facility, maturing in January 2017.
UNS Energy Corporation has a US$150 million ($208 million) unsecured committed revolving credit facility, maturing in October 2020, with the option of two one-year extensions.
CH Energy Group has a US$50 million ($69 million) unsecured committed revolving credit facility, maturing in July 2020, that can be utilized for general corporate purposes.
FHI has a $30 million unsecured committed revolving credit facility, maturing in April 2018, that is available for general corporate purposes.
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at December 31, 2015, the Corporation's credit ratings were as follows:
| Standard & Poor's ("S&P") | A- / Stable (long-term corporate and unsecured debt credit rating) |
| DBRS | A (low) / Stable (unsecured debt credit rating) |
The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and management's commitment to maintaining reasonable levels of debt at the holding company level. In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC Holdings Corp. ("ITC") (Note 35), S&P affirmed the Corporation's long-term corporate credit rating at A-, revised its unsecured debt rating to BBB+ from A-, and revised its outlook on the Corporation to negative from stable. Similarly, in February 2016 DBRS placed the Corporation's credit rating under review with negative implications.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and BECOL is the US dollar.
As at December 31, 2015, the Corporation's corporately issued US$1,535 million (December 31, 2014 - US$1,496 million) long-term debt had been designated as an effective hedge of a portion of the Corporation's foreign net investments. As at December 31, 2015, the Corporation had approximately US$3,137 million (December 31, 2014 - US$2,762 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income.
On an annual basis, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.38 as at December 31, 2015 would increase or decrease earnings per common share of Fortis by approximately 4 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where possible, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk (Notes 15, 16 and 31).
Commodity Price Risk
UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and natural gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of natural gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates (Note 31).
33. COMMITMENTS
As at December 31, 2015, the Corporation's consolidated commitments in each of the next five years and for periods thereafter, excluding repayments of long-term debt and capital lease and finance obligations separately disclosed in Notes 15 and 16, respectively, are as follows:
| Due | Due | ||||||
| within | Due in | Due in | Due in | Due in | after | ||
| ($ in millions) | Total | 1 year | year 2 | year 3 | year 4 | year 5 | 5 years |
| Interest obligations on long-term debt | 9,435 | 536 | 512 | 507 | 495 | 488 | 6,897 |
| Renewable power purchase obligations (1) | 1,589 | 93 | 93 | 92 | 92 | 92 | 1,127 |
| Gas purchase obligations (2) | 1,449 | 366 | 253 | 222 | 153 | 131 | 324 |
| Power purchase obligations (3) | 1,440 | 281 | 209 | 180 | 102 | 36 | 632 |
| Long-term contracts - UNS Energy (4) | 1,057 | 146 | 141 | 105 | 102 | 82 | 481 |
| Capital cost (5) | 488 | 19 | 19 | 19 | 19 | 19 | 393 |
| Operating lease obligations (6) | 181 | 12 | 11 | 11 | 11 | 8 | 128 |
| Renewable energy credit purchase agreements (7) | 162 | 13 | 13 | 13 | 13 | 13 | 97 |
| Purchase of Springerville Common Facilities (8) | 147 | - | 53 | - | - | - | 94 |
| Defined benefit pension and OPEB funding contributions (Note 27) | 139 | 49 | 12 | 8 | 9 | 9 | 52 |
| Waneta Partnership promissory note (Note 17) | 72 | - | - | - | - | 72 | - |
| Joint-use asset and shared service agreements | 53 | 3 | 3 | 3 | 3 | 3 | 38 |
| Other (9) | 71 | 15 | 12 | 16 | 3 | - | 25 |
| Total | 16,283 | 1,533 | 1,331 | 1,176 | 1,002 | 953 | 10,288 |
| (1) | TEP and UNS Electric are party to 20-year long-term renewable PPAs totalling approximately US$1,148 million as at December 31, 2015, which require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities that have achieved commercial operation. While TEP and UNS Electric are not required to make payments under these contracts if power is not delivered, the table above includes estimated future payments based on expected power deliveries. These agreements have various expiry dates through 2035. TEP has entered into additional long-term renewable PPAs to comply with renewable energy standards of the State of Arizona; however, the Company's obligation to purchase power under these agreements does not begin until the facilities are operational. In February 2016 one of the generating facilities achieved commercial operation, increasing estimated future payments of renewable PPAs by US$58 million, which is not included in the table above. |
| (2) | Certain of the Corporation's subsidiaries, mainly FortisBC Energy and Central Hudson, enter into contracts for the purchase of gas, gas transportation and storage services. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2015. At Central Hudson, the obligations are based on tariff rates, negotiated rates and market prices as at December 31, 2015. |
| (3) | Power purchase obligations include various power purchase contracts held by certain of the Corporation's subsidiaries, as described below. FortisBC Energy In March 2015 FortisBC Energy entered into an Electricity Supply Agreement with BC Hydro for the purchase of electricity supply to the Tilbury Expansion Project, with purchase obligations totalling $513 million as at December 31, 2015. FortisBC Electric Power purchase obligations for FortisBC Electric, totalling $292 million as at December 31, 2015, mainly include a PPA with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term, as approved by the BCUC. The capacity and energy to be purchased under this agreement do not relate to a specific plant. In addition, in November 2011 FortisBC Electric executed the Waneta Expansion Capacity Agreement ("WECA"), allowing FortisBC Electric to purchase 234 MW of capacity for 40 years, effective April 2015, as approved by the BCUC. Amounts associated with the WECA have not been included in the Commitments table as they are to be paid by FortisBC Electric to a related party and such a related-party transaction would be eliminated upon consolidation with Fortis. FortisOntario Power purchase obligations for FortisOntario, totalling $208 million as at December 31, 2015, primarily include two long-term take-or-pay contracts between Cornwall Electric and Hydro-Quebec Energy Marketing for the supply of electricity and capacity, both expiring in December 2019. The first contract provides approximately 237 GWh of energy per year and up to 45 MW of capacity at any one time. The second contract provides 100 MW of capacity and provides a minimum of 300 GWh of electricity per contract year. Maritime Electric Power purchase obligations for Maritime Electric, totalling $194 million as at December 31, 2015, primarily include two take-or-pay contracts for the purchase of either capacity or energy, expiring in February 2019 and November 2032, as well as an Energy Purchase Agreement with New Brunswick Power ("NB Power") expiring in February 2019. Central Hudson Central Hudson's power purchase obligations totalled US$124 million as at December 31, 2015. In June 2014 Central Hudson entered into a contract to purchase available installed capacity from the Danskammer Generating Facility from October 2014 through August 2018 with approximately US$76 million in purchase commitments remaining as at December 31, 2015. During 2015 Central Hudson entered into agreements to purchase electricity on a unit-contingent basis at defined prices during peak load periods from June 2015 through August 2016, replacing existing contracts which expired in March 2015. |
| (4) | UNS Energy has entered into various long-term contracts for the purchase and delivery of coal to fuel its generating facilities, the purchase of gas transportation services to meet its load requirements, and the purchase of transmission services for purchased power, with obligations totalling US$440 million, US$261 million and US$63 million, respectively, as at December 31, 2015. Amounts paid under contracts for the purchase and delivery of coal depend on actual quantities purchased and delivered. Certain of these contracts also have price adjustment clauses that will affect future costs under the contracts. As a result of the restructuring of the ownership of the San Juan generating station in January 2016, a new coal supply agreement came into effect under which TEP's minimum purchase obligations are US$137 million, which is not included in the previous table. |
| (5) | Maritime Electric has entitlement to approximately 4.55% of the output from NB Power's Point Lepreau nuclear generating station for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit. |
| (6) | Operating lease obligations include certain office, warehouse, natural gas T&D asset, rail car, land easement and rights-of-way, and vehicle and equipment leases. |
| (7) | UNS Energy is party to renewable energy credit purchase agreements, totalling approximately US$117 million as at December 31, 2015, to purchase the environmental attributions from retail customers with solar installations. Payments for the renewable energy credit purchase agreements are paid in contractually agreed-upon intervals based on metered renewable energy production. |
| (8) | UNS Energy has entered into a commitment to exercise its fixed-price purchase provision to purchase an undivided 50% leased interest in the Springerville Common Facilities if the lease is not renewed, for a purchase price of US$106 million, with one facility to be acquired in 2017 and the remaining two facilities to be acquired in 2021 (Note 16). |
| (9) | Other contractual obligations include various other commitments entered into by the Corporation and its subsidiaries, including PSU, RSU and DSU Plan obligations and asset retirement obligations. |
Other Commitments
Capital Expenditures: The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. The regulated utilities' capital expenditures are largely driven by the need to ensure continued and enhanced performance, reliability and safety of the electricity and gas systems and to meet customer growth. The Corporation's consolidated capital expenditure program, including capital spending at its non-regulated operations, is forecast to be approximately $1.9 billion for 2016. Over the five years 2016 through 2020, the Corporation's consolidated capital expenditure program is expected to be approximately $9 billion, which has not been included in the Commitments table.
Other: CH Energy Group is party to an investment to develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling US$1.7 billion, of which CH Energy Group's maximum commitment is US$182 million. CH Energy Group issued a parental guarantee to assure the payment of maximum commitment of US$182 million. As at December 31, 2015, no payment obligation is expected under this guarantee.
FortisBC Energy issued commitment letters to customers, totalling $33 million as at December 31, 2015, to provide Energy Efficiency and Conservation ("EEC") funding under the EEC program approved by the BCUC.
Caribbean Utilities is party to primary and secondary fuel supply contracts and is committed to purchasing approximately 60% and 40%, respectively, of the Company's diesel fuel requirements under the contracts for the operation of its diesel-powered generating plant. The approximate combined quantity under the contracts for 2016 is 20 million imperial gallons. Fortis Turks and Caicos has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 12 million imperial gallons per annum.
The Corporation's long-term regulatory liabilities of $1,340 million as at December 31, 2015 have been excluded from the Commitments table, as the final timing of settlement of many of the liabilities is subject to further regulatory determination or the settlement periods are not currently known. The nature and amount of the long-term regulatory liabilities are detailed in Note 8.
34. 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 or results of operations.
The following describes the nature of the Corporation's contingencies.
UNS Energy
Springerville Unit 1
In November 2014 the Springerville Unit 1 third-party owners filed a complaint ("FERC Action") against TEP with FERC, alleging that TEP had not agreed to wheel power and energy for the third-party owners in the manner specified in the existing Springerville Unit 1 facility support agreement between TEP and the third-party owners and for the cost specified by the third-party owners. The third-party owners requested an order from FERC requiring such wheeling of the third-party owners' energy from their Springerville Unit 1 interests beginning in January 2015 for the price specified by the third-party owners. In February 2015 FERC issued an order denying the third-party owners' complaint. In March 2015 the third-party owners filed a request for rehearing in the FERC Action, which FERC denied in October 2015. In December 2015 the third-party owners appealed FERC's order denying the third-party owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015 TEP filed an unopposed motion to intervene in the Ninth Circuit appeal.
In December 2014 the third-party owners filed a complaint ("New York Action") against TEP in the Supreme Court of the State of New York, New York County. In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged and the court's subsequent ruling on the motions, the third-party owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; and that TEP breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses. The third amended complaint seeks US$71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The third-party owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015 the third-party owners filed a motion for summary judgment on their claim that TEP failed to pay certain of the third-party owners' claimed expenses.
In December 2014 and January 2015, Wilmington Trust Company, as owner trustees and lessors under the leases of the third-party owners, sent notices to TEP that alleged that TEP had defaulted under the third-party owners' leases. The notices demanded that TEP pay liquidated damages totalling approximately US$71 million. In letters to the owner trustees, TEP denied the allegations in the notices.
In April 2015 TEP filed a demand for arbitration with the American Arbitration Association ("AAA") seeking an award of the owner trustees and co-trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015 the third-party owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The third-party owners' arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the third-party owners' fees and expenses. TEP and the third-party owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015 the third-party owners filed an amended arbitration demand adding claims that TEP has converted the third-party owners' water rights and certain emission reduction payments and that TEP is improperly dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity.
In October 2015 the arbitration panel granted TEP's motion for interim relief, ordering the owner trustees and co-trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the third-party owners' motion for interim relief, which had requested that TEP be enjoined from dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling the third-party owners' entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015. The arbitration hearing is scheduled for July 2016.
In November 2015 TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming owner trustee and co-trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015 the owner trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order.
As at December 31, 2015, TEP billed the third-party owners approximately US$23 million for their pro-rata share of Springerville Unit 1 expenses and US$4 million for their pro-rata share of capital expenditures, none of which had been paid as of February 17, 2016.
TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the claims, the Company cannot determine estimates of the range of loss, if any, at this time and, accordingly, no amount has been accrued in the consolidated financial statements. TEP intends to vigorously defend itself against the claims asserted by the third-party owners and to vigorously pursue the claims it has asserted against the third-party owners.
TEP and the third-party owners have agreed to stay these litigation matters relating to Springerville Unit 1 in furtherance of settlement negotiations. However, there is no assurance that a settlement will be reached or that the litigation will not continue.
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$43 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The mine reclamation liability recorded as at December 31, 2015 was US$25 million (December 31, 2014 - US$22 million), and represents the present value of the estimated future liability (Note 17).
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 8 (ix)).
Central Hudson
Site Investigation and Remediation Program
Central Hudson and its predecessors owned and operated MGPs to serve their customers' heating and lighting needs. These plants manufactured gas from coal and oil beginning in the mid to late 1800s, with all sites ceasing operations by the 1950s. This process produced certain by-products that may pose risks to human health and the environment.
The New York State Department of Environmental Conservation ("DEC"), which regulates the timing and extent of remediation of MGP sites in New York State, has notified Central Hudson that it believes the Company or its predecessors at one time owned and/or operated MGPs at seven sites in Central Hudson's franchise territory. The DEC has further requested that the Company investigate and, if necessary, remediate these sites under a Consent Order, Voluntary Clean-up Agreement or Brownfield Clean-up Agreement. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2015, an obligation of US$92 million (December 31, 2014 - US$105 million) was recognized in respect of site investigation and remediation and, based upon cost model analysis completed in 2014, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$169 million.
Central Hudson has notified its insurers and intends to seek reimbursement from insurers for remediation, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return. In the three-year rate order issued by the PSC in June 2015, Central Hudson's authorization to defer all site investigation and remediation costs was reaffirmed and extended through June 2018 (Note 8 (iv)).
Asbestos Litigation
Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,350 asbestos cases have been raised, 1,167 remained pending as at December 31, 2015. Of the cases no longer pending against Central Hudson, 2,027 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which include FortisBC Electric, use of a road on top of the dam. The Government of British Columbia estimates its damages and the damages of the homeowners, on whose behalf it is claiming, to be approximately $15 million. While FortisBC Electric has notified its insurers, it has been advised by the Government of British Columbia that a response to the claim is not required at this time. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FHI
In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
35. SUBSEQUENT EVENT
On February 9, 2016, Fortis and ITC (NYSE:ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 Fortis common shares per ITC common share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
ITC is the largest independent pure-play electric transmission company in the United States. ITC owns and operates high-voltage transmission facilities in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, serving a combined peak load exceeding 26,000 MW along approximately 15,600 miles of transmission line. In addition, ITC is a public utility and independent transmission owner in Wisconsin. ITC's tariff rates are regulated by FERC, which has been one of the most consistently supportive utility regulators in North America providing reasonable returns and equity ratios. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, those of FERC, the Committee on Foreign Investment in the United States, and the United States Federal Trade Commission/Department of Justice under the Hart-Scott Rodino Antitrust Improvement Act. The closing of the Acquisition is expected to occur in late 2016.
The pending Acquisition is in alignment with the Corporation's business model and acquisition strategy, and is expected to provide approximately 5% accretion to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses and assuming a stable currency exchange environment. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the Acquisition.
The financing of the Acquisition has been structured to allow Fortis to maintain investment-grade credit ratings and is consistent with the Corporation's existing capital structure. Financing of the cash portion of the Acquisition will be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of up to 19.9% of ITC to one or more infrastructure-focused minority investors. In addition, Fortis has 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. These non-revolving term credit facilities are repayable in full on the first anniversary of their advance and although syndication is not required, Fortis expects that these bridge facilities will be syndicated.
Upon completion of the Acquisition, ITC will become a subsidiary of Fortis and approximately 27% of the common shares of Fortis will be held by ITC shareholders. In connection with the Acquisition, Fortis will become a registrant with the U.S. Securities and Exchange Commission and will apply to list its common shares on the New York Stock Exchange and will continue to have its shares listed on the TSX.
36. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation. As a result of the adoption of new accounting policies in 2015 (Note 3), the following changes to the Corporation's comparative financial statements were made:
- the reclassification of deferred financing costs of approximately $65 million from long-term other assets to long-term debt on the Corporation's consolidated balance sheet as at December 31, 2014 (Note 15); and
- the presentation of all deferred income tax assets and liabilities as long term. This change in presentation resulted in the following reclassifications: (i) a decrease in current deferred income taxes assets of $158 million; (ii) a decrease in long-term deferred income tax assets of $62 million; (iii) a decrease in current deferred income tax liabilities of $9 million; and (iv) a decrease in long-term deferred income tax liabilities of $211 million on the consolidated balance sheet as at December 31, 2014 (Note 26). In addition, the Corporation also reclassified the associated regulatory deferred income taxes as long-term, resulting in the following reclassifications: (i) a decrease in current regulatory assets of $18 million; (ii) a decrease in long-term regulatory assets of $92 million; (iii) a decrease in current regulatory liabilities of $19 million; and (iv) a decrease in long-term regulatory liabilities of $91 million on the consolidated balance sheet as at December 31, 2014 (Note 8).
Contact Information:
Executive Vice President, Chief Financial Officer
Fortis Inc.
709.737.2822