ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - Nov. 7, 2014) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) released its third quarter results today. "The third quarter was a period of significant transition for Fortis," says Barry Perry, President, Fortis. "We closed the acquisition of UNS Energy, announced a strategic review of Fortis Properties and implemented our new organizational structure."
Net earnings attributable to common equity shareholders for the third quarter were $14 million, or $0.06 per common share, compared to $48 million, or $0.23 per common share, for the third quarter of 2013. Results for the third quarter of 2014 were impacted by a number of non-recurring expenses associated with the acquisition of UNS Energy Corporation ("UNS Energy"). Earnings for the third quarter were reduced by $35 million, or $0.16 per common share, due to one-time acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy. Interest expense of $23 million after tax, or $0.11 per common share, including the make-whole payment, associated with convertible debentures issued to finance a portion of the acquisition of UNS Energy was recognized in the third quarter. Excluding the above-noted impacts, net earnings attributable to common equity shareholders for the third quarter of 2014 were $72 million, or $0.33 per common share, an increase of $24 million, or $0.10 per common share, from the same period last year.
On August 15, 2014, Fortis acquired UNS Energy for US$60.25 per common share in cash, for a purchase price of approximately US$4.5 billion, including the assumption of approximately US$2.0 billion of debt. UNS Energy, headquartered in Tucson, Arizona, is engaged through its primary subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, and serves approximately 658,000 electricity and gas customers. The net cash purchase price of approximately $2.7 billion (US$2.5 billion) was initially financed through: (i) drawings of $2 billion under the Corporation's acquisition credit facilities, consisting of a $1.7 billion short-term bridge facility, repayable in full nine months following its advance, and a $300 million medium-term bridge facility, repayable in full on the second anniversary of its advance (together, the "Acquisition Credit Facilities"); (ii) available cash on hand; and (iii) drawings of US$265 million under the Corporation's revolving credit facility.
"Closing the acquisition of UNS Energy was a major milestone for Fortis. It further diversifies regulated assets and enhances our presence significantly in the United States," says Stan Marshall, Chief Executive Officer, Fortis.
The Corporation's regulated utilities contributed earnings of $89 million, an increase of $34 million from the third quarter of 2013. The increase was driven by earnings contribution of $37 million at UNS Energy from the date of acquisition. 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. FortisAlberta's earnings were $2 million higher quarter over quarter mainly due to restoration costs of approximately $1.5 million recognized in the third quarter of 2013 related to flooding in southern Alberta in June 2013. Earnings at Caribbean Regulated Electric Utilities were $2 million higher than the third quarter of 2013, driven by electricity sales growth. The increases were partially offset by lower earnings at Central Hudson, due to the impact of higher depreciation and operating expenses during the two-year rate freeze period post acquisition in June 2013, and at FortisBC Electric, due to the impact of lower-than-expected finance charges in 2013, which were not subject to regulatory deferral mechanisms last year.
"Fortis regulated utilities performed well during the quarter. The expedited closing of the UNS Energy transaction contributed significantly during the quarter. Excluding the one-time acquisition-related expenses, the acquisition of UNS Energy was immediately accretive to earnings per common share," states Perry.
Non-Regulated Fortis Generation contributed $4 million to earnings, compared to $8 million for the third quarter of 2013. The decrease was associated with decreased production in Belize, due to lower rainfall.
Non-Utility operations contributed earnings of $9 million, an increase of $3 million from the third quarter of 2013. Earnings for the third quarter of 2013 reflected a net loss of approximately $2.5 million at non-regulated Griffith Energy Services, Inc., which was sold in March 2014. In September 2014 the Corporation announced that it will engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. This review process commenced in October 2014 and is expected to continue through the balance of 2014 and into 2015.
Corporate and Other expenses were $9 million higher quarter over quarter, excluding the impacts of interest expense on the convertible debentures and acquisition-related expenses. The increase for the quarter was primarily due to higher finance charges, largely due to the acquisition of UNS Energy, and higher operating expenses. The increase in operating expenses was mainly due to employee-related expenses, including approximately $8 million in after-tax retirement expenses recognized in the third quarter of 2014 and share-based compensation expenses as a result of share price appreciation, combined with higher legal and consulting fees and general inflationary increases. The increase in Corporate and Other expenses was partially offset by a $5 million foreign exchange gain in the third quarter of 2014 compared to a $2 million foreign exchange loss in the same quarter last year, a higher income tax recovery and interest income.
A decision on multi-year performance-based rate-setting applications in British Columbia was received in September 2014 and did not have a material impact on earnings in the quarter. A generic cost of capital proceeding is continuing in Alberta and the outcome is expected in the fourth quarter of 2014. A hearing related to FortisAlberta's combined capital tracker application for 2013 through 2015, which is an application for revenue increases related to its capital expenditure program, was held in October 2014. FortisAlberta continues to recognize capital tracker revenue based on the interim regulatory decision granting 60% of the applied for capital tracker amounts. A decision on the combined capital tracker application is expected in the first quarter of 2015. In July 2014 Central Hudson filed a general rate application to establish rates effective mid-2015.
The financing associated with the acquisition of UNS Energy is substantially complete. Fortis completed the sale of $1.8 billion 4% convertible unsecured subordinated debentures represented by Installment Receipts. 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 the Corporation's Acquisition Credit Facilities initially used to finance a portion of the UNS Energy acquisition. Following the receipt of the final installment, on October 28, 2014, approximately 58.2 million common shares of Fortis were issued on conversion of the debentures. 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. The net proceeds were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy.
The Corporation and its regulated utilities raised over $1 billion in long-term debt year-to-date 2014. In March 2014 Fortis priced a private placement of US$500 million in senior unsecured notes. The notes were issued in multiple tranches with terms to maturity ranging from 5 years to 30 years and coupon rates ranging from 2.92% to 5.03%. On June 30, 2014, Fortis issued US$213 million of the senior unsecured notes, the net proceeds of which were used to repay US-dollar denominated borrowings on the Corporation's credit facility and for general corporate purposes. The remaining US$287 million of the senior unsecured notes were issued on September 15, 2014. Net proceeds were used to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis that matured in October 2014 and $125 million 5.56% unsecured debentures of a subsidiary that matured in September 2014, and for general corporate purposes. In September 2014 FortisAlberta issued $275 million unsecured debentures in two tranches, comprised of 10-year $150 million unsecured debentures at 3.30% and 30-year $125 million unsecured debentures at 4.11%. Net proceeds were used to repay $200 million 5.33% unsecured debentures that matured in October 2014, to finance capital expenditures and for general corporate purposes. In October 2014 FortisBC Electric issued 30-year $200 million unsecured debentures at 4.00%. Net proceeds will be used to repay $140 million 5.48% unsecured debentures maturing in November 2014, to finance capital expenditures and for general corporate purposes.
Cash flow from operating activities was $648 million year-to-date 2014 compared to $666 million for the same period last year. The decrease was primarily due to unfavourable changes in working capital.
Consolidated capital expenditures were approximately $875 million year-to-date 2014. Construction of the $900 million, 335-megawatt ("MW") Waneta Expansion hydroelectric generating facility ("Waneta Expansion") in British Columbia continues on time and on budget, with completion of the facility expected in spring 2015. Approximately $648 million has been invested in the Waneta Expansion since construction began in late 2010. In October 2014 FortisBC started construction of its Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia. The Tilbury expansion will be included in regulated rate base and is estimated to cost approximately $400 million. It will include a second LNG tank and a new liquefier, both to be in service in the second half of 2016.
The Corporation's capital program is expected to total $1.8 billion in 2014, which includes capital spending of approximately $450 million (US$400 million) at UNS Energy from the date of acquisition. In December 2014 UNS Energy is expected to purchase Unit 3 of the Gila River generating station, which is a gas-fired combined-cycle unit with a capacity of 550 MW, for US$219 million. Over the five-year period 2014 through 2018, the Corporation's capital program is expected to exceed $9 billion.
"Following a decade of strong growth, primarily achieved through acquisitions, Fortis is now entering a period of significant organic growth, with a four-year compound annual growth rate in rate base through 2018 estimated at 7%," says Perry. "Fortis is also pursuing significant natural gas investment opportunities, particularly in British Columbia. Two new regulated projects - further expansion of the Tilbury LNG facility and the Woodfibre pipeline expansion, could increase the four-year compound annual growth rate in rate base through 2018 to 8.5%," he concludes.
Teleconference to Discuss Third Quarter 2014 Results
A teleconference and webcast will be held on November 7 at 10:00 a.m. (Eastern). Barry Perry, President and incoming Chief Executive Officer, Fortis, and Karl Smith, Executive Vice President, Chief Financial Officer, Fortis, will discuss the Corporation's third quarter 2014 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 November 17, 2014. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 22025223.
| Interim Management Discussion and Analysis |
| For the three and nine months ended September 30, 2014 |
| Dated November 7, 2014 |
FORWARD-LOOKING INFORMATION
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the interim unaudited consolidated financial statements and notes thereto for the three and nine months ended September 30, 2014 and the MD&A and audited consolidated financial statements for the year ended December 31, 2013 included in the Corporation's 2013 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "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 and is based on information currently available to the Corporation's management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation's intent to engage in a review of strategic options for its hotel and commercial real estate business; the expectation that UNS Energy Corporation ("UNS Energy") is able to satisfy the requirements of its customer base and meet future peak demand requirements; the expectation that there will be a significant reduction in the use of coal in certain of UNS Energy's generating facilities by 2020; the expectation that the amalgamation of the FortisBC Energy companies will be effective on December 31, 2014 and upon amalgamation the allowed capital structure and allowed rate of return on common shareholders' equity ("ROE") of the amalgamated entity will be consistent with FortisBC Energy Inc.;
the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast gross consolidated capital expenditures for 2014 and total capital spending over the five-year period 2014 through 2018; the nature, timing and amount of certain capital projects and their expected costs and time to complete; 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 2014 capital expenditure programs, operating and interest costs, and dividend payments; the expected consolidated long-term debt maturities and repayments in 2014 and on average annually over the next five years; management's intention to refinance borrowings under long-term committed credit facilities with long-term permanent financing; the expectation that long-term debt will not be settled prior to maturity; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to capital in the near to medium 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 2014; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation that economic conditions in the State of Arizona will improve; the impact of advances in technology and new energy efficiency standards on the Corporation's results of operations; the impact of new or revised environmental laws and regulations on the Corporation's results of operations; the expectation that any liability from current legal proceedings would not have a material adverse effect on the Corporation's consolidated financial position and results of operations; the belief that the Corporation has a strong, well-positioned case supporting the unconstitutionality of the expropriation of the Corporation's investment in Belize; the expectation that ongoing labour negotiations will be settled in 2014; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: a favorable outlook for the potential sale of assets or shares in the hotel and commercial real estate market; the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; FortisAlberta's continued recovery of its cost of service and ability to earn its allowed ROE under performance-based rate-setting ("PBR"), which commenced for a five-year term effective January 1, 2013; 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; no material capital project and financing cost overrun related to the construction of the non-regulated Waneta Expansion hydroelectric generating facility; sufficient liquidity and capital resources;
the expectation that the Corporation will receive appropriate compensation from the Government of Belize ("GOB") for fair value of the Corporation's investment in Belize Electricity that was expropriated by the GOB; the expectation that Belize Electric Company Limited will not be expropriated by the GOB; 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 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; 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, the Corporation's MD&A for the year ended December 31, 2013 and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2014 include, but are not limited to: uncertainty of the impact a continuation of a low interest rate environment may have on the allowed ROE at the Corporation's regulated utilities; uncertainty regarding the treatment of certain capital expenditures at FortisAlberta under the newly implemented PBR mechanism; risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; and the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis.
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 more than $25 billion and fiscal 2013 revenue exceeding $4 billion. Its regulated utilities account for approximately 90% of total assets and serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation's non-utility investment is comprised of hotels and commercial real estate in Canada.
Year-to-date September 30, 2014, the Corporation's electricity distribution systems met a combined peak demand of 9,054 megawatts ("MW") and its gas distribution system met a peak day demand of 1,541 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2014 and to the "Corporate Overview" section of the 2013 Annual MD&A.
The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are generally determined under cost of service ("COS") regulation and, in certain circumstances, performance-based rate-setting ("PBR") mechanisms. Generally, under COS regulation, the respective regulatory authority sets customer gas and/or electricity 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 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. 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 COS and earn its allowed ROE.
Earnings of regulated utilities are generally 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) timing differences within an annual financial reporting period between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.
SIGNIFICANT ITEMS
Acquisition of UNS Energy Corporation: On August 15, 2014, Fortis acquired all of the outstanding common shares of UNS Energy Corporation ("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. The net cash purchase price of approximately $2.7 billion (US$2.5 billion) was initially financed through: (i) drawings of $2 billion under the Corporation's acquisition credit facilities, consisting of a $1.7 billion short-term bridge facility, repayable in full nine months following its advance, and a $300 million medium-term bridge facility, repayable in full on the second anniversary of its advance (together, the "Acquisition Credit Facilities"); (ii) available cash on hand; and (iii) drawings of US$265 million under the Corporation's revolving credit facility.
UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through its primary subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 658,000 electricity and gas customers. UNS Energy has three regulated utility subsidiaries: Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas") (collectively, the "UNS Utilities"). UNS Energy's utility operations are vertically integrated with generation, transmission and distribution being regulated by the Arizona Corporation Commission ("ACC") and the U.S. Federal Energy Regulatory Commission ("FERC"). For further information on UNS Energy, refer to the "Segmented Results of Operations - Regulated Electric & Gas Utilities - United States" section of this MD&A.
As part of the regulatory approvals required in connection with the acquisition, Fortis has committed to provide UNS Energy's customers with certain benefits, including but not limited to: (i) providing the retail consumers of the UNS Utilities with bill credits totalling US$30 million over five years (US$10 million in year one and US$5 million annually in years two through five); (ii) UNS Energy and the UNS Utilities adopting certain ring-fencing and corporate governance provisions; (iii) limiting dividends paid from the UNS Utilities to UNS Energy to 60% of the UNS Utilities' respective net income for a period of five years or until such time that their respective equity capitalization reaches 50% of total capital as accounted for in accordance with US GAAP; and (iv) Fortis making an equity infusion totalling US$220 million through UNS Energy into the UNS Utilities after the closing of the acquisition, which was completed within 60 days of the acquisition.
The above-noted commitments of $33 million (US$30 million), or $20 million (US$18 million) after tax, associated with customer benefits offered by the Corporation to close the acquisition of UNS Energy were recognized in the Corporation's earnings for the third quarter of 2014. Acquisition-related expenses of approximately $20 million ($15 million after tax) and $24 million ($18 million after tax) were recognized for the third quarter and year-to-date 2014, respectively.
The acquisition is consistent with the Corporation's strategy of investing in quality regulated utility assets in Canada and the United States and is immediately accretive to earnings per common share of Fortis, excluding one-time acquisition-related costs. The Corporation's consolidated midyear rate base increased by approximately US$3 billion as a result of the acquisition of UNS Energy. In addition, the acquisition has further mitigated business risk for Fortis by enhancing the geographic diversification of the Corporation's regulated assets, resulting in no more than one-third of total assets being located in any one regulatory jurisdiction.
Convertible Debentures Represented by Installment Receipts: To finance a portion of the acquisition of UNS Energy, in January 2014, Fortis, through a direct wholly owned subsidiary, completed the sale of $1.8 billion aggregate principal amount of 4% convertible unsecured subordinated debentures, represented by Installment Receipts (the "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 Toronto Stock Exchange ("TSX") under the symbol "FTS.IR" from January 9, 2014 to October 27, 2014. The Convertible Debentures are not listed. The Convertible Debentures will mature on January 9, 2024 and accrued interest at an annual rate of 4% per $1,000 principal amount of Convertible Debentures from January 9, 2014 to and including the Final Installment Date, after which the interest rate is 0%.
Since the Final Installment Date occurred prior to the first anniversary of the closing of the offering, holders of Convertible Debentures who paid the final installment in October 2014 received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Installment Date to and including January 9, 2015. Approximately $33 million ($23 million after tax) and $67 million ($47 million after tax) in interest expense associated with the Convertible Debentures, including the make-whole payment, was recognized in the third quarter and year-to-date 2014, respectively. An additional $5 million ($4 million after tax) in interest expense will be recognized in the fourth quarter of 2014 representing interest on the Convertible Debentures from October 1, 2014 to and including the Final Installment Date, for a total of approximately $72 million ($51 million after tax) recognized in 2014.
At the option of the holders, each fully paid Convertible Debenture is 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 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. After the Final Installment Date, any Convertible Debentures not converted may be redeemed by Fortis at a price equal to their principal amount. At maturity, Fortis will have the right to pay the principal amount due in common shares, which will be valued at 95% of the weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity date.
The proceeds of the first installment payment of the Convertible Debentures received on January 9, 2014 were approximately $599 million, or $561 million net of issue costs, which were used to partially finance the acquisition of UNS Energy and for general corporate purposes. The proceeds of the final installment payment received on October 28, 2014 were approximately $1.2 billion, or $1.165 billion net of issue costs. The net proceeds of the final installment were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy.
First Preference Shares: 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. The net proceeds were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy.
Review of Strategic Options for Fortis Properties: In September 2014 the Corporation announced that it will engage in a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. This review process commenced in October 2014 and is expected to continue through the balance of 2014 and into 2015.
Long-Term Debt Offerings: In March 2014 Fortis priced a private placement to US-based institutional investors of US$500 million in senior unsecured notes. The notes were issued in June and September in multiple tranches with terms to maturity ranging from 5 years to 30 years and coupon rates ranging from 2.92% to 5.03%. The weighted average term to maturity is approximately 11 years and the weighted average coupon rate is 3.85%.
In June 2014 Fortis issued US$213 million of the senior unsecured notes. 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 Fortis issued the remaining US$287 million of the senior unsecured notes. Net proceeds were used to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis that matured in October 2014 and $125 million 5.56% unsecured debentures of a subsidiary that matured in September 2014, and for general corporate purposes.
In September 2014 FortisAlberta issued $275 million unsecured debentures in two tranches, comprised of 10-year $150 million unsecured debentures at 3.30% and 30-year $125 million unsecured debentures at 4.11%. Net proceeds were used to repay $200 million 5.33% unsecured debentures that matured in October 2014, to finance capital expenditures and for general corporate purposes.
In October 2014 FortisBC Electric issued 30-year $200 million unsecured debentures at 4.00%. Net proceeds will be used to repay $140 million 5.48% unsecured debentures maturing in November 2014, to finance capital expenditures and for general corporate purposes.
Sale of Griffith: In March 2014 Griffith Energy Services, Inc. ("Griffith") was sold for proceeds of approximately $105 million (US$95 million). The results of operations have been presented as discontinued operations on the consolidated statements of earnings for the three and nine months ended September 30, 2014. Earnings for the first quarter of 2014 included $5 million associated with Griffith from normal operations to the date of sale.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common share and total shareholder return as the primary measures of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the third quarter and year-to-date periods ended September 30, 2014 and 2013 are provided in the following table.
| Consolidated Financial Highlights (Unaudited) | |||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||||||
| ($ millions, except for common share data) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |||||||
| Revenue | 1,197 | 915 | 282 | 3,708 | 2,818 | 890 | |||||||
| Energy Supply Costs | 406 | 311 | 95 | 1,488 | 1,098 | 390 | |||||||
| Operating Expenses | 384 | 286 | 98 | 1,010 | 713 | 297 | |||||||
| Depreciation and Amortization | 181 | 140 | 41 | 478 | 399 | 79 | |||||||
| Other Income (Expenses), Net | (43 | ) | 2 | (45 | ) | (37 | ) | (36 | ) | (1 | ) | ||
| Finance Charges | 159 | 103 | 56 | 406 | 284 | 122 | |||||||
| Income Tax (Recovery) Expense | (8 | ) | 8 | (16 | ) | 40 | 4 | 36 | |||||
| Earnings from Continuing Operations | 32 | 69 | (37 | ) | 249 | 284 | (35 | ) | |||||
| (Loss) Earnings from Discontinued Operations, Net of Tax | - | (2 | ) | 2 | 5 | (2 | ) | 7 | |||||
| Earnings Before Extraordinary Item | 32 | 67 | (35 | ) | 254 | 282 | (28 | ) | |||||
| Extraordinary Gain, Net of Tax | - | - | - | - | 22 | (22 | ) | ||||||
| Net Earnings | 32 | 67 | (35 | ) | 254 | 304 | (50 | ) | |||||
| Net Earnings Attributable to: | |||||||||||||
| Non-Controlling Interests | 3 | 3 | - | 8 | 7 | 1 | |||||||
| Preference Equity Shareholders | 15 | 16 | (1 | ) | 42 | 44 | (2 | ) | |||||
| Common Equity Shareholders | 14 | 48 | (34 | ) | 204 | 253 | (49 | ) | |||||
| Net Earnings | 32 | 67 | (35 | ) | 254 | 304 | (50 | ) | |||||
| Earnings per Common Share from Continuing Operations | |||||||||||||
| Basic ($) | 0.06 | 0.24 | (0.18 | ) | 0.93 | 1.17 | (0.24 | ) | |||||
| Diluted ($) | 0.06 | 0.24 | (0.18 | ) | 0.93 | 1.17 | (0.24 | ) | |||||
| Earnings per Common Share | |||||||||||||
| Basic ($) | 0.06 | 0.23 | (0.17 | ) | 0.95 | 1.27 | (0.32 | ) | |||||
| Diluted ($) | 0.06 | 0.23 | (0.17 | ) | 0.95 | 1.27 | (0.32 | ) | |||||
| Weighted Average Common Shares Outstanding (# millions) | 215.6 | 212.0 | 3.6 | 214.6 | 199.1 | 15.5 | |||||||
| Cash Flow from Operating Activities | 62 | 106 | (44 | ) | 648 | 666 | (18 | ) | |||||
Revenue
The increase in revenue for the quarter was driven by the acquisition of UNS Energy in August 2014. An increase in the commodity cost of natural gas charged to customers at the FortisBC Energy companies, an increase in the base component of rates at most of the regulated utilities, higher electricity sales, and favourable foreign exchange associated with the translation of US dollar-denominated revenue also contributed to the increase in revenue.
The increase year to date was primarily due to the same factors discussed above for the quarter, combined with the acquisition of Central Hudson Gas & Electric Corporation ("Central Hudson") in June 2013 and higher gas volumes.
Energy Supply Costs
The increase in energy supply costs for the quarter was driven by the acquisition of UNS Energy. A higher commodity cost of natural gas at the FortisBC Energy companies and higher electricity sales also contributed to the increase in fuel, power and natural gas purchases.
The increase in energy supply costs year to date was primarily due to the same factors discussed above for the quarter, combined with the acquisition of Central Hudson and higher gas volumes.
Operating Expenses
The increase in operating expenses for the quarter was primarily due to the acquisition of UNS Energy and general inflationary and employee-related cost increases, including approximately $9 million ($8 million after tax) in retirement expenses recognized in the third quarter of 2014.
The increase year to date was primarily due to the same factors discussed above for the quarter, combined with the acquisition of Central Hudson.
Depreciation and Amortization
The increase in depreciation and amortization for the quarter was primarily due to the acquisition of UNS Energy and continued investment in energy infrastructure at the Corporation's regulated utilities.
The increase year to date was primarily due to the same factors discussed above for the quarter, combined with the acquisition of Central Hudson.
Other Income (Expenses), Net
The decrease in other income, net of expenses, for the quarter was mainly due to higher acquisition-related expenses associated with UNS Energy, including customer benefits offered by the Corporation to close the acquisition. The decrease was partially offset by favourable foreign exchange on the translation into Canadian dollars of the Corporation's US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity.
Other income, net of expenses, year to date was comparable with the same period last year. Total acquisition-related expenses associated with UNS Energy in 2014 and an increase in interest income were comparable to acquisition-related expenses associated with Central Hudson in 2013.
Finance Charges
The increase in finance charges for the quarter and year to date was primarily due to approximately $33 million ($23 million after tax) and $67 million ($47 million after tax) in interest expense, including the make-whole payment, associated with Convertible Debentures issued to finance a portion of the acquisition of UNS Energy. The increase was also due to the UNS Energy and Central Hudson acquisitions, including interest expense on debt issued to complete the financing of the acquisitions.
Income Tax (Recovery) Expense
The increase in income tax recovery for the quarter was mainly due to a decrease in earnings before income taxes.
The increase in income tax expense year to date was primarily due to the impact of an income tax recovery of $23 million in 2013, due to the enactment of higher deductions associated with Part VI.1 tax, and the release of income tax provisions of $7 million in 2013.
(Loss) Earnings from Discontinued Operations, Net of Tax
Earnings for the third quarter and year-to-date 2013 included a net loss from discontinued operations of approximately $2.5 million at Griffith. Approximately $5 million in earnings from discontinued operations, net of tax, was recognized in the first quarter of 2014 associated with Griffith, which was sold in March 2014, from normal operations to the date of sale.
Extraordinary Gain, Net of Tax
An approximate $22 million after-tax extraordinary gain was recognized in the first quarter of 2013 on the settlement of expropriation matters associated with the Exploits River Hydro Partnership ("Exploits Partnership").
Net Earnings Attributable to Common Equity Shareholders
Earnings were impacted by a number of non-recurring items. Earnings for the third quarter and year-to-date 2014 were reduced by $35 million and $38 million, respectively, due to acquisition-related expenses and customer benefits offered to obtain regulatory approval of the acquisition of UNS Energy, compared to $32 million in acquisition-related expenses associated with Central Hudson in the second quarter and year-to-date 2013. Earnings for the quarter and year-to-date 2014 were reduced by $23 million and $47 million, respectively, in after-tax interest expense associated with the Convertible Debentures, including the make-whole payment. Earnings year-to-date 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. Earnings year-to-date 2014 included $5 million from discontinued operations associated with Griffith, compared to a net loss of approximately $2.5 million for the third quarter and year-to-date 2013. Earnings year-to-date 2013 included an approximate $22 million extraordinary gain associated with the Exploits Partnership.
Excluding the above-noted impacts of acquisition-related expenses, interest expense on the Convertible Debentures and Griffith, net earnings attributable to common equity shareholders for the third quarter were $72 million compared to $51 million for the same period last year. The increase was driven by earnings contribution of $37 million at UNS Energy from the date of acquisition. The increase was partially offset by higher Corporate and Other expenses, primarily due to higher finance charges, largely due to the acquisition of UNS Energy, and higher operating expenses. The increase in operating expenses was mainly due to employee-related expenses, including approximately $8 million in after-tax retirement expenses recognized in the third quarter of 2014 and share-based compensation expenses as a result of share price appreciation, combined with higher legal and consulting fees and general inflationary increases. The increase in Corporate and Other expenses was partially offset by a $5 million foreign exchange gain in the third quarter of 2014, compared to a $2 million foreign exchange loss in the same quarter last year, a higher income tax recovery and interest income.
Excluding the above-noted impacts of acquisition-related expenses, interest expense on the Convertible Debentures, Part VI.1 tax impacts, the Exploits Partnership and Griffith, net earnings attributable to common equity shareholders year to date were $284 million compared to $243 million for the same period last year. The increase was mainly due to the same reasons discussed above for the quarter, combined with earnings contribution from Central Hudson and higher earnings at Caribbean Regulated Electric Utilities, driven by electricity sales growth. The increase was partially offset by higher finance charges associated with the acquisition of Central Hudson in June 2013 and the impact of the release of income tax provisions of $7 million in 2013.
SEGMENTED RESULTS OF OPERATIONS
The basis of segmentation of the Corporation's reportable segments is consistent with that disclosed in the 2013 Annual MD&A, except as follows as a result of the acquisition of UNS Energy. UNS Energy is reported as part of the segment "Regulated Electric & Gas Utilities - United States" and the former "Other Canadian Electric Utilities" segment is now "Eastern Canadian Electric Utilities" and now includes Newfoundland Power, Maritime Electric and FortisOntario.
| Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited) | |||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |||||||
| Regulated Electric & Gas Utilities - United States | |||||||||||||
| UNS Energy | 37 | - | 37 | 37 | - | 37 | |||||||
| Central Hudson | 8 | 12 | (4 | ) | 33 | 12 | 21 | ||||||
| 45 | 12 | 33 | 70 | 12 | 58 | ||||||||
| Regulated Gas Utilities - Canadian | |||||||||||||
| FortisBC Energy Companies | (13 | ) | (13 | ) | - | 78 | 78 | - | |||||
| Regulated Electric Utilities - Canadian | |||||||||||||
| FortisAlberta | 27 | 25 | 2 | 78 | 76 | 2 | |||||||
| FortisBC Electric | 9 | 11 | (2 | ) | 34 | 37 | (3 | ) | |||||
| Eastern Canadian | 13 | 14 | (1 | ) | 46 | 60 | (14 | ) | |||||
| 49 | 50 | (1 | ) | 158 | 173 | (15 | ) | ||||||
| Regulated Electric Utilities - Caribbean | 8 | 6 | 2 | 21 | 15 | 6 | |||||||
| Non-Regulated - Fortis Generation | 4 | 8 | (4 | ) | 16 | 35 | (19 | ) | |||||
| Non-Regulated - Non-Utility | 9 | 6 | 3 | 21 | 15 | 6 | |||||||
| Corporate and Other | (88 | ) | (21 | ) | (67 | ) | (160 | ) | (75 | ) | (85 | ) | |
| Net Earnings Attributable to Common Equity Shareholders | 14 | 48 | (34 | ) | 204 | 253 | (49 | ) | |||||
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 ELECTRIC & GAS UTILITIES - UNITED STATES
UNS ENERGY
UNS Energy is primarily comprised of three regulated utilities: TEP, UNS Electric and UNS Gas. TEP is a vertically integrated regulated electric utility and UNS Energy's largest operating subsidiary, representing approximately 85% of UNS Energy's total assets at September 30, 2014. The Company generates, transmits and distributes electricity to approximately 415,000 retail electric customers in southeastern Arizona. TEP's service territory covers 2,991 square kilometres and includes a population of approximately 1,000,000 people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. The Company has sufficient generating capacity which, together with existing power purchase agreements and expected generation plant additions, should satisfy the requirements of its customer base and meet expected future peak demand requirements. TEP also sells wholesale electricity to other entities in the western United States.
UNS Electric is a vertically integrated regulated electric utility, representing approximately 9% of UNS Energy's total assets at September 30, 2014. The Company generates, transmits and distributes electricity to approximately 93,000 retail electric customers in Arizona's Mohave and Santa Cruz counties, which have a combined population of approximately 250,000.
UNS Gas is a regulated gas distribution company, representing approximately 6% of UNS Energy's total assets at September 30, 2014. The Company serves approximately 150,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties, which have a combined population of approximately 700,000.
TEP and UNS Electric currently own or lease generation resources with an aggregate capacity of 2,392 MW, including 18 MW of solar capacity. Several of the generating assets in which UNS Energy has an interest are jointly owned. As at September 30, 2014, approximately 70% of UNS Energy's generating capacity is fuelled by coal. UNS Energy has a long-term energy resource diversification strategy to provide long-term rate stability for customers, mitigate environmental impacts, comply with regulatory requirements and leverage existing utility infrastructure. TEP is reducing its reliance on coal over the next few years by replacing portions of existing coal generation with efficient combined-cycle gas turbines and renewables, particularly by adding solar generating capacity, and expects coal to represent less than 50% of generating capacity by the year 2020.
UNS Energy's electric utilities met a combined peak demand of 2,620 MW year-to-date 2014, which occurred in the third quarter. Earnings for the electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment. UNS Gas met a peak day demand of 79 TJ year-to-date 2014, which occurred in the first quarter. Earnings for UNS Gas are generally highest in the first and fourth quarters due to space-heating requirements.
Regulation
The UNS Utilities are regulated by the ACC regarding such matters as retail electric and gas rates, construction, operations, financing, accounting, transactions with affiliated parties and issuance of securities. Certain activities of the utilities are subject to regulation by FERC under the Federal Power Act (United States), including such matters as the terms and prices of transmission services and wholesale electricity sales.
The UNS Utilities operate under COS regulation as administered by the ACC. The ACC provides for the use of a historical test year in the establishment of retail electric and gas rates for the utilities and, pursuant to this method, the determination of the approved rate of return on original cost rate base and capital structure and all reasonable and prudently incurred costs establishes the revenue requirement upon which the Company's customer rates are determined. Retail electric and gas rates are set to provide the utilities with an opportunity to recover their costs of service 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. Once rates are approved, they are not adjusted as a result of actual COS being different from that which was estimated, other than for certain prescribed costs that are eligible for deferral account treatment.
Rates charged to retail customers include flow-through mechanisms that allow the utilities to recover the prudently incurred actual costs of its fuel, transmission, and energy purchases, and the prudent cost of contracts for hedging fuel and purchased power costs. The difference between costs recovered through rates and actual fuel, transmission and energy costs prudently incurred to provide retail electric and gas service is subject to deferral account treatment.
TEP and UNS Electric are required to comply with the ACC's Renewable Energy Standard ("RES"), which requires the utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans 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.
TEP, UNS Electric and UNS Gas are required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's Energy Efficiency ("EE") Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs of implementing DSM programs. 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.
TEP's allowed ROE is set at 10.0% on a capital structure of 43.5% common equity, effective from July 1, 2013. The existing rate order at TEP also provides for an Environmental Compliance Adjustor mechanism that allows for recovery of the costs of complying with environmental standards required by federal or other government agencies between rate cases. 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.
Financial Highlights
| Financial Highlights (Unaudited) (1) | Quarter |
| Period Ended September 30 | 2014 |
| Average US:CDN Exchange Rate (2) | 1.09 |
| Electricity Sales (gigawatt hours ("GWh")) | 2,070 |
| Gas Volumes (petajoules ("PJ")) | 1 |
| Revenue ($ millions) | 249 |
| Earnings ($ millions) | 37 |
| (1) | Financial results of UNS Energy are from August 15, 2014, the date of acquisition. For additional information on the acquisition of UNS Energy, refer to the "Significant Items - Acquisition of UNS Energy" section of this MD&A. |
| (2) | The reporting currency of UNS Energy is the US dollar. |
Electricity Sales & Gas Volumes
Electricity sales for the third quarter from the date of acquisition were 2,070 GWh. Electricity sales for the full third quarter were 4,219 GWh compared to 4,123 GWh for the same period last year. The increase was primarily due to higher short-term wholesale sales.
Gas volumes for the third quarter from the date of acquisition were approximately 0.5 PJ. Gas volumes for the full third quarter were 1 PJ, consistent with the same period last year.
Revenue
Revenue for the third quarter from the date of acquisition was US$227 million. Revenue for the full third quarter was US$457 million compared to US$437 million for the same period last year. The increase was primarily due to higher electricity sales and increases associated with the fuel recovery mechanism.
Earnings
Earnings for the third quarter from the date of acquisition were US$34 million. Earnings for the full third quarter, excluding acquisition-related expenses recognized by UNS Energy, were US$66 million, comparable to US$68 million for the same period last year.
CENTRAL HUDSON (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | |||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |
| Average US:CDN Exchange Rate (2) | 1.09 | 1.04 | 0.05 | 1.09 | 1.04 | 0.05 | |
| Electricity Sales (GWh) | 1,323 | 1,420 | (97 | ) | 3,899 | 1,420 | 2,479 |
| Gas Volumes (PJ) | 3 | 4 | (1 | ) | 18 | 4 | 14 |
| Revenue ($ millions) | 173 | 170 | 3 | 635 | 170 | 465 | |
| Earnings ($ millions) | 8 | 12 | (4 | ) | 33 | 12 | 21 |
| (1) | Financial results of Central Hudson are from June 27, 2013, the date of acquisition. |
| (2) | The reporting currency of Central Hudson is the US dollar. |
Electricity Sales & Gas Volumes
The decrease in electricity sales for the quarter was primarily due to lower average consumption as a result of cooler temperatures, which reduced the use of air conditioning and other cooling equipment. Year-to-date electricity sales were 3,899 GWh compared to 3,950 GWh for the same period last year. The decrease was mainly due to lower average consumption in the third quarter of 2014, partially offset by higher average consumption in the first quarter of 2014 due to colder temperatures.
Gas volumes for the quarter and year-to-date were comparable with the same periods last year.
Seasonality impacts delivery revenue at Central Hudson, as electricity sales are highest during the summer months, primarily due to the use of air conditioning and other cooling equipment, and gas volumes are highest during the winter months, primarily due to space-heating usage.
Revenue
The increase in revenue for the quarter was mainly due to approximately $8 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase was partially offset by the recovery from customers of lower commodity costs.
Revenue year to date was US$579 million compared to US$511 million for the same period last year. The increase in revenue was primarily due to the recovery from customers of overall higher commodity costs, mainly in the first half of 2014, which were driven by higher wholesale prices. Foreign exchange associated with the translation of US dollar-denominated revenue also had a favourable impact on revenue year to date, as discussed above for the quarter.
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.
Earnings
The decrease in earnings for the quarter was primarily due to the impact of higher depreciation and operating expenses during the two-year rate freeze period post acquisition in June 2013.
Earnings year to date were US$30 million compared to US$34 million for the same period last year. The decrease was due to the same factors discussed above for the quarter, partially offset by the impact of US$2 million in expenses recognized in the first quarter of 2013 as a result of a regulatory order denying the deferral of certain storm-restoration costs.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||
| Gas Volumes (PJ) | 25 | 25 | - | 136 | 132 | 4 | ||
| Revenue ($ millions) | 208 | 194 | 14 | 1,003 | 932 | 71 | ||
| (Loss) Earnings ($ millions) | (13 | ) | (13 | ) | - | 78 | 78 | - |
| (1) | Primarily includes FortisBC Energy Inc., FortisBC Energy (Vancouver Island) Inc. and FortisBC Energy (Whistler) Inc. |
Gas Volumes
Gas volumes for the quarter were consistent with the same period last year. The year-to-date increase in gas volumes was primarily due to higher average consumption as a result of colder temperatures in the first quarter of 2014.
As at September 30, 2014, the total number of customers served by the FortisBC Energy companies was approximately 960,000, an increase of 4,000 customers from December 31, 2013.
The FortisBC Energy companies earn 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 commodity cost of natural gas from those forecast to set customer rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the FortisBC Energy companies as a major portion of the gas distributed is used for space heating. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters.
Revenue
The increase in revenue for the quarter and year to date was primarily due to a higher commodity cost of natural gas charged to customers and an increase in the delivery component of customer rates, effective January 1, 2014. Higher gas volumes also contributed to the increase in revenue year to date.
Earnings
Earnings for the quarter and year to date were comparable with the same periods last year.
In September 2014 the regulatory decision on FortisBC Energy Inc.'s Multi-Year PBR Plan was received. The outcome of the decision did not have a material impact on earnings at the FortisBC Energy companies year-to-date 2014. In March 2014 the regulatory decision on the second stage of the Generic Cost of Capital Proceeding ("GCOC") Proceeding in British Columbia was received, resulting in an increase in the allowed ROE at FortisBC Energy (Whistler) Inc. ("FEWI") and an increase in the common equity component of capital structure at FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FEWI, effective January 1, 2013. The cumulative impact of this regulatory decision was recognized in the first quarter of 2014, when the decision was received, and did not have a material impact on earnings. For further details on the Multi-Year PBR Plan and the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of the MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance |
| Energy Deliveries (GWh) | 4,152 | 3,925 | 227 | 12,926 | 12,411 | 515 |
| Revenue ($ millions) | 131 | 119 | 12 | 386 | 354 | 32 |
| Earnings ($ millions) | 27 | 25 | 2 | 78 | 76 | 2 |
Energy Deliveries
The increase in energy deliveries for the quarter and year to date was driven by growth in the number of customers. The total number of customers increased by approximately 12,000 year over year as at September 30, 2014, as a result of strong economic growth in the Province of Alberta. Higher average consumption by residential, commercial and farm and irrigation customers for the quarter and year to date also contributed to the increase, mainly due to changes in temperatures. Lower levels of precipitation also had a favorable impact on energy deliveries for farm and irrigation customers. Increased consumption by oilfield customers for the quarter was mainly due to improved commodity prices for oil and gas.
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.
Revenue
The increase in revenue for the quarter and year to date was primarily due to an interim increase in customer distribution rates, effective January 1, 2014, growth in the number of customers and an increase in revenue related to flow-through costs to customers. The increase in revenue year to date was partially offset by lower net transmission revenue, of which approximately $2 million was recognized in the first quarter of 2013 associated with the finalization of 2012 net transmission volume variances.
Earnings
The increase in earnings for the quarter and year to date was mainly due to restoration costs of approximately $1.5 million recognized in the third quarter of 2013 related to flooding in southern Alberta in June 2013. Higher income tax recoveries, rate base growth and growth in the number of customers were partially offset by the timing of certain operating expenses. The increase in earnings year to date was also partially offset by lower net transmission revenue, as discussed above.
Earnings associated with rate base growth continue to be tempered by the interim regulatory decision granting 60% of the revenue requirement associated with the capital tracker component of the PBR mechanism. For further details on FortisAlberta's Capital Tracker Application, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
FORTISBC ELECTRIC (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||
| Electricity Sales (GWh) | 732 | 752 | (20 | ) | 2,333 | 2,324 | 9 | |
| Revenue ($ millions) | 78 | 74 | 4 | 244 | 230 | 14 | ||
| Earnings ($ millions) | 9 | 11 | (2 | ) | 34 | 37 | (3 | ) |
| 1 | Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned Walden Power Partnership. |
Electricity Sales
The decrease in electricity sales for the quarter was mainly due to lower average consumption due to cooler temperatures.
The increase in electricity sales year to date was driven by customer growth and higher average consumption as a result of colder temperatures in the first quarter of 2014.
Revenue
The increase in revenue for the quarter was primarily due to higher amortization of flow-through adjustments owing to customers and an interim refundable increase in base electricity rates, effective January 1, 2014, partially offset by a decrease in electricity sales.
The increase in revenue year to date was primarily due to the same factors discussed above for the quarter, however, was favourably impacted by an increase in electricity sales.
Earnings
The decrease in earnings for the quarter and year to date was primarily due to the impact of lower-than-expected finance charges in 2013, which were not subject to regulatory deferral mechanisms last year, and the timing of operating expenses. Effective January 1, 2014, variances in finance charges from those used to establish customer rates are subject to regulatory deferral mechanisms. The decrease in earnings year to date was partially offset by the favourable impact related to the timing of recognition of regulatory deferrals.
The outcome of the GCOC Proceeding in British Columbia did not have an impact on earnings variances for the quarter and year-to-date periods. For further details on the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||
| Electricity Sales (GWh) | 1,529 | 1,530 | (1 | ) | 6,173 | 5,989 | 184 | |
| Revenue ($ millions) | 198 | 202 | (4 | ) | 742 | 714 | 28 | |
| Earnings ($ millions) | 13 | 14 | (1 | ) | 46 | 60 | (14 | ) |
| 1 | Comprised of Newfoundland Power, Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power. |
Electricity Sales
Electricity sales for the quarter were comparable with the same period last year. The increase in electricity sales year to date was driven by higher average consumption by residential and commercial customers in all regions, due to colder temperatures in the first half of 2014, and customer growth in Newfoundland and Prince Edward Island, including an increase in the number of customers using electricity for home heating.
Revenue
The decrease in revenue for the quarter was mainly due to the flow through in customer electricity rates of lower energy supply costs at FortisOntario.
The increase in revenue year to date was driven by electricity sales growth and an increase in base electricity rates at Newfoundland Power, effective July 1, 2013. The increase was partially offset by the flow through in customer electricity rates of lower energy supply costs at FortisOntario, as discussed above for the quarter, and a higher regulatory rate of return adjustment at Maritime Electric year-to-date 2014 compared to the same period last year.
Earnings
The decrease in earnings for the quarter was primarily due to the rebasing of customer electricity rates at Newfoundland Power as a result of the Company's 2013/2014 General Rate Application decision, effective July 1, 2013. The rebasing of customer electricity rates impacted the timing of Newfoundland Power's earnings, resulting in higher earnings for the first half of 2014 and a decrease in earnings in the third quarter of 2014.
The decrease in earnings year to date was mainly due to income tax recoveries recognized in the second quarter of 2013 of approximately $13 million at Newfoundland Power and $4 million at Maritime Electric, due to the enactment of higher deductions associated with Part VI.1 tax. Excluding the $17 million income tax recovery, earnings increased by $3 million year to date compared to the same period last year. The impact of electricity sales growth was partially offset by a higher regulatory rate of return adjustment at Maritime Electric and higher operating costs at Newfoundland Power associated with restoration efforts following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance |
| Average US:CDN Exchange Rate (2) | 1.09 | 1.04 | 0.05 | 1.09 | 1.02 | 0.07 |
| Electricity Sales (GWh) | 207 | 197 | 10 | 584 | 560 | 24 |
| Revenue ($ millions) | 85 | 77 | 8 | 237 | 213 | 24 |
| Earnings ($ millions) | 8 | 6 | 2 | 21 | 15 | 6 |
| (1) | Comprised of Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling interest and two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited ("FortisTCI") and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos") |
| (2) | The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. |
Electricity Sales
The increase in electricity sales for the quarter and year to date was primarily due to warmer temperatures, which increased air conditioning load. Growth in the number of customers and increases in tourism also contributed to the increase in electricity sales.
Revenue
The increase in revenue for the quarter and year to date was driven by approximately $4 million and $15 million, respectively, of favourable foreign exchange associated with the translation of US dollar-denominated revenue, electricity sales growth, and an increase in base customer electricity rates at Caribbean Utilities.
Earnings
The increase in earnings for the quarter and year to date was primarily due to electricity sales growth and favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher overall operating expenses, net of higher capitalized overhead costs at Fortis Turks and Caicos.
NON-REGULATED - FORTIS GENERATION (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||
| Energy Sales (GWh) | 77 | 104 | (27 | ) | 298 | 242 | 56 | |
| Revenue ($ millions) | 8 | 12 | (4 | ) | 30 | 24 | 6 | |
| Earnings ($ millions) | 4 | 8 | (4 | ) | 16 | 35 | (19 | ) |
| (1) | Comprised of the financial results of non-regulated generation assets in Belize, Ontario, British Columbia and Upstate New York, with a combined generating capacity of 103 MW, mainly hydroelectric |
Energy Sales
The decrease in energy sales for the quarter was due to decreased production in Belize due to lower rainfall.
The increase in energy sales year to date was due to increased production in Belize in the first half of 2014 due to higher rainfall and increased production in Upstate New York due to a generating unit being returned to service in October 2013.
Revenue
The decrease in revenue for the quarter was due to decreased production in Belize.
The increase in revenue year to date was driven by increased production in Belize in the first half of 2014, increased production in Upstate New York, and favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings for the quarter was due to decreased production in Belize.
The decrease in earnings year to date was primarily due to the recognition of an approximate $22 million after-tax extraordinary gain on the settlement of expropriation matters associated with the Exploits Partnership in the first quarter of 2013. Excluding the $22 million extraordinary gain, earnings increased by $3 million year to date compared to the same period last year. The increase in earnings was driven by increased production in Belize and Upstate New York, and favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by approximately $2 million in business development costs associated with investigating a potential hydroelectric generating facility in British Columbia.
NON-REGULATED - NON-UTILITY (1)
| Financial Highlights (Unaudited) | ||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance |
| Revenue | 68 | 68 | - | 187 | 186 | 1 |
| Earnings | 9 | 6 | 3 | 21 | 15 | 6 |
| (1) | Comprised of Fortis Properties and Griffith. Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.8 million square feet of commercial office and retail space, primarily in Atlantic Canada. Griffith was acquired in June 2013 as part of the acquisition of CH Energy Group and was sold in March 2014. As such, the results of operations of Griffith have been presented as discontinued operations on the consolidated statements of earnings and, accordingly, revenue excludes amounts associated with Griffith. Earnings, however, reflect the financial results of Griffith from June 2013 to March 2014. |
Revenue
Revenue at Fortis Properties for the quarter and year to date was comparable to the same periods last year.
Earnings
Year-to-date 2014, earnings included $5 million associated with Griffith from normal operations to the date of sale in March 2014. Earnings for the third quarter and year-to-date 2013 included a net loss of approximately $2.5 million at Griffith.
Excluding the impact of Griffith, Fortis Properties contributed earnings of $9 million for the third quarter, comparable to the same period last year. Fortis Properties contributed earnings of approximately $16 million year-to-date 2014 compared to approximately $17.5 million for the same period last year. The decrease in earnings was primarily due to lower performance at the Hospitality Division and higher depreciation due to capital asset additions and improvements, partially offset by lower finance charges.
In September 2014 the Corporation announced that it will engage in a review of strategic options for Fortis Properties' hotel and commercial real estate business. For further details, refer to the "Significant Items" section of this MD&A.
CORPORATE AND OTHER (1)
| Financial Highlights (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||||||
| Revenue | 9 | 6 | 3 | 24 | 19 | 5 | ||||||
| Operating Expenses | 16 | 2 | 14 | 30 | 8 | 22 | ||||||
| Depreciation and Amortization | 1 | - | 1 | 2 | 1 | 1 | ||||||
| Other Income (Expenses), Net | (48 | ) | (1 | ) | (47 | ) | (49 | ) | (45 | ) | (4 | ) |
| Finance Charges | 57 | 13 | 44 | 125 | 34 | 91 | ||||||
| Income Tax Recovery | (40 | ) | (5 | ) | (35 | ) | (64 | ) | (38 | ) | (26 | ) |
| (73 | ) | (5 | ) | (68 | ) | (118 | ) | (31 | ) | (87 | ) | |
| Preference Share Dividends | 15 | 16 | (1 | ) | 42 | 44 | (2 | ) | ||||
| Net Corporate and Other Expenses | (88 | ) | (21 | ) | (67 | ) | (160 | ) | (75 | ) | (85 | ) |
| (1) | Includes Fortis net Corporate expenses; non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group and UNS Energy Corporation; and the financial results of FHI's wholly owned subsidiary FortisBC Alternative Energy Services Inc. |
Net Corporate and Other expenses were significantly impacted by the following items:
- Finance charges of $33 million ($23 million after tax) for the third quarter and $67 million ($47 million after tax) year-to-date 2014 associated with the Convertible Debentures issued in January 2014 to finance the acquisition of UNS Energy, including the expense associated with the make-whole payment;
- Other expenses of approximately $33 million (US$30 million), or $20 million (US$18 million) after tax, associated with customer benefits offered by the Corporation to close the acquisition of UNS Energy, recognized in the third quarter of 2014, compared to approximately $41 million (US$40 million), or $26 million (US$26 million) after tax, associated with customer and community benefits offered by the Corporation to close the acquisition of Central Hudson, recognized in the second quarter of 2013;
- Other expenses of $20 million ($15 million after tax) and $24 million ($18 million after tax) for the third quarter and year-to-date 2014, respectively, related to the acquisition of UNS Energy, compared to approximately $8 million ($6 million after tax) in the second quarter of 2013 related to the acquisition of Central Hudson;
- A $6 million income tax recovery in the first half of 2013, due to the enactment of higher deductions associated with Part VI.1 tax;
- A foreign exchange gain of approximately $5 million for the third quarter and year-to-date 2014, compared to a foreign exchange loss of approximately $2 million for the third quarter of 2013 and a foreign exchange gain of approximately $3 million year-to-date 2013, associated with the Corporation's US dollar-denominated long-term other asset, representing the book value of the Corporation's expropriated investment in Belize Electricity; and
- The release of income tax provisions of approximately $2 million and $7 million for the third quarter and year-to-date 2013, respectively.
Excluding the above-noted items, net Corporate and Other expenses were $35 million for the quarter and $80 million year to date, compared to $21 million and $59 million, respectively, for the same periods last year. The increase was primarily due to higher finance charges and operating expenses, partially offset by a higher income tax recovery and interest income.
The increase in finance charges for the quarter and year to date was primarily due to the acquisition of Central Hudson in June 2013 and UNS Energy in August 2014, including: (i) the US$325 million notes offering in October 2013; (ii) the US$213 million and US$287 million notes offerings in June 2014 and September 2014, respectively; (iii) drawings under the Corporation's committed credit facility and $2 billion Acquisition Credit Facilities to initially finance the acquisitions; and (iv) higher credit facility fees associated with the Corporation's $2 billion Acquisition Credit Facilities secured as bridge financing. Finance charges were also impacted by unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense. The increase was partially offset by higher capitalized interest associated with the financing of the construction of the non-regulated Waneta Expansion hydroelectric generating facility ("Waneta Expansion").
The increase in operating expenses was mainly due to higher employee-related expenses, including approximately $9 million ($8 million after tax) and $13 million ($11 million after tax) in non-recurring retirement expenses for the quarter and year to date, respectively, and increased share-based compensation expenses of approximately $1.5 million ($1 million after tax) and $4 million ($2.5 million after tax) for the quarter and year to date, respectively, as a result of share price appreciation, combined with higher legal and consulting fees and general inflationary increases.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated electric and gas utilities year-to-date 2014 are summarized as follows.
| NATURE OF REGULATION | ||||||||
| Allowed Returns (%) | Significant Features | |||||||
| Regulated Utility |
Regulatory Authority |
Allowed Common Equity (%) |
2012 |
2013 |
2014 |
Future or Historical Test Year Used to Set Customer Rates |
||
| ROE | ||||||||
| TEP | ACC | 43.5 | 10.25(1) | 10.13(1) | 10.00(1) | COS/ROE | ||
| UNS Electric | ACC | 52.6 | 9.75(1) | 9.75(1) | 9.50(1) | ROEs established by the ACC | ||
| UNS Gas | ACC | 50.8 | 9.67(1) | 9.75(1) | 9.75(1) | |||
| Historical Test Year | ||||||||
| Central Hudson | New York State Public Service Commission ("PSC") | 48 |
10.00 |
10.00 |
10.00 |
COS/ROE |
||
| Earnings sharing mechanism effective July 1, 2013 |
||||||||
| ROE established by the PSC | ||||||||
| Future Test Year | ||||||||
| FEI | British Columbia Utilities Commission ("BCUC") | 38.5(2) |
9.50 |
8.75 |
8.75 |
COS/ROE FEI - PBR mechanism for 2014 through 2019 |
||
| FEVI | BCUC | 41.5(2) |
10.00 |
9.25 |
9.25 |
ROEs established by the BCUC |
||
| FEWI | BCUC | 41.5(2) | 10.00 | 9.50 | 9.50 | |||
| 2013 test year with 2014 through 2019 | ||||||||
| rates set using PBR mechanism | ||||||||
| FortisBC Electric | BCUC | 40 |
9.90 |
9.15 |
9.15 |
COS/ROE |
||
| 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 Commission ("AUC") | 41(3) |
8.75 |
8.75(3) |
8.75(3) |
COS/ROE |
||
| 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 Power | Newfoundland and Labrador Board of Commissioners of Public Utilities ("PUB") | 45 |
8.80 +/- 50 bps |
8.80 +/- 50 bps |
8.80 +/- 50 bps |
COS/ROE ROE established by the PUB |
||
| Future Test Year | ||||||||
| Maritime Electric | Island Regulatory and Appeals Commission | 40 |
9.75 |
9.75 |
9.75 |
COS/ROE |
||
| ROE established by the Government of PEI under the PEI Energy Accord | ||||||||
| Future Test Year | ||||||||
| Fortis Ontario | Ontario Energy Board | 40 |
8.01 - 9.85 |
8.93 - 9.85 |
8.93 - 9.85 |
COS/ROE (4) |
||
| Future test year and incentive | ||||||||
| rate-setting mechanism | ||||||||
| ROA | ||||||||
| Caribbean Utilities | Electricity Regulatory Authority ("ERA") | N/A |
7.25 - 9.25 |
6.50 - 8.50 |
7.00 - 9.00 |
COS/ROA |
||
| Rate-cap adjustment mechanism based on published consumer price indices |
||||||||
| Historical Test Year | ||||||||
| Fortis Turks and Caicos | Government of the Turks and Caicos Islands | N/A |
15.00 - 17.50 (5) |
15.00 - 17.50(5) |
15.00 - 17.50(5) |
COS/ROA |
||
| 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) | Effective January 1, 2013. For 2012, the allowed deemed equity component of the capital structure was 40%. |
| (3) | Capital structure and allowed ROE for 2013 and 2014 are interim and are subject to change based on the outcome of a cost of capital proceeding. |
| (4) | 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. |
| (5) | Achieved ROAs at the utilities were 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 largest regulated utilities year-to-date 2014.
UNS Energy
There were no significant regulatory decisions and applications at UNS Energy from the date of acquisition. For further information on the nature of regulation at UNS Energy, refer to the "Regulated Electric & Gas Utilities - United States" section of this MD&A.
Central Hudson
In July 2014 Central Hudson filed a General Rate Application seeking to increase electricity and natural gas delivery rates effective July 1, 2015. A delivery rate freeze was implemented for electricity and natural gas delivery rates through to June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson committed to invest US$215 million in capital expenditures during the two-year delivery rate freeze period ending June 30, 2015. In its General Rate Application, the Company has requested an allowed ROE of 9.0% with a 48% common equity component of capital structure. The current rate order includes an allowed ROE of 10.0% with a 48% common equity component of capital structure.
In April 2014 the PSC issued an order instituting a proceeding Reforming the Energy Vision to reform New York State's energy industry and regulatory practices. The initiative will seek to further a number of policy objectives and seek to determine the appropriate role of distribution utilities in furthering these objectives, as well as considering regulatory changes to better align utility interests with energy policy objectives.
FortisBC Energy Companies and FortisBC Electric
In February 2014 the FortisBC Energy companies received regulatory approval for the amalgamation of its regulated utilities. The regulator approved the adoption of common rates for the majority of natural gas customers, to be phased in over a three-year period. The amalgamation received the consent of the Lieutenant Governor in Council in May 2014 and is expected to be effective on December 31, 2014.
In May 2013 the BCUC issued its decision on the first stage of the GCOC Proceeding in British Columbia. Effective January 1, 2013, the decision set the allowed ROE of the benchmark utility, FEI, at 8.75% with a 38.5% common equity component of capital structure. The common equity component of capital structure will remain in effect until December 31, 2015. Effective January 1, 2014 through December 31, 2015, the BCUC has also introduced an Automatic Adjustment Mechanism ("AAM") to set the allowed ROE for the benchmark utility on an annual basis. The AAM will take effect when the long-term Government of Canada bond yield exceeds 3.8%. In January 2014 the BCUC confirmed that the necessary conditions for the AAM to be triggered for the 2014 allowed ROE have not been met; therefore, the benchmark allowed ROE remains at 8.75% for 2014. FEVI, FEWI and FortisBC Electric's allowed ROEs and common equity component of capital structures were determined in the second stage of the GCOC Proceeding. However, as a result of the decision on the first stage of the GCOC Proceeding, which reduced the allowed ROE of the benchmark utility by 75 basis points, the interim allowed ROEs for FEVI, FEWI and FortisBC Electric decreased to 9.25%, 9.25% and 9.15%, respectively, effective January 1, 2013, while the deemed common equity component of capital structures remained unchanged.
In March 2014 the BCUC issued its decision on the second stage of the GCOC Proceeding. Effective January 1, 2013, the decision set the common equity component of capital structure for FEVI and FEWI at 41.5%, and reaffirmed the common equity component of capital structure for FortisBC Electric at 40%. The BCUC reaffirmed for FEVI and FortisBC Electric a risk premium over the benchmark utility of 50 basis points and 40 basis points, respectively, and set FEWI's equity risk premium at 75 basis points, which represented an increase of 25 basis points. The resulting allowed ROEs, effective January 1, 2013, for FEVI, FortisBC Electric and FEWI are 9.25%, 9.15%, and 9.50%, respectively. The cumulative impact of the outcome of the second stage of the GCOC Proceeding was recognized in the first quarter of 2014 and did not have a material impact on earnings.
Once amalgamation of the FortisBC Energy companies is completed, the allowed ROE and common equity component of capital structure for the amalgamated entity will be set the same as the benchmark utility, FEI.
In September 2014 the BCUC issued its decisions on FEI's and FortisBC Electric's Multi-Year PBR Plans for 2014-2018. As part of the PBR decisions the terms were extended to 2019. The approved PBR Plans incorporate incentive mechanisms for improving operating efficiencies. Operation and maintenance costs and base capital expenditures during the PBR period are subject to a formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity improvement 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 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 October 2014 FEI filed a PBR decision Compliance Filing with the BCUC which updated the 2014 revenue requirement and rates based on the PBR decision. The Compliance Filing resulted in a delivery rate increase of 0.4% over the existing interim increase of 1.4%. FEI has implemented permanent 2014 delivery rates effective November 1, 2014 to reflect the additional delivery rate increase. FEI will recover the January 2014 to October 2014 revenue deficiency between interim and permanent rates through a deferral mechanism. FortisBC Electric expects to file its updated 2014 revenue requirement in November 2014, which will incorporate the PBR decision and request that the existing interim rates be made final. The PBR decision is not expected to have a material impact on the midyear rate base from that used to calculate interim rates for FEI and FortisBC Electric.
FortisAlberta
In May 2014 FortisAlberta filed a combined 2013, 2014 and 2015 Capital Tracker Application as required by the regulator. The application requested capital tracker revenue of approximately $23 million for 2013, $48 million for 2014 and $69 million for 2015. A hearing related to the combined Capital Tracker Application was held in October 2014. FortisAlberta continues to recognize capital tracker revenue based on the interim regulatory decision granting 60% of the applied for capital tracker amounts. Any adjustment by the regulator to the interim decision will result in an adjustment to FortisAlberta's revenue. Such an adjustment would be recognized in the consolidated financial statements when the regulatory decision is received, or when sufficient information is available to reasonably estimate the required adjustment in accordance with US GAAP.
In September 2014 FortisAlberta filed its 2015 Annual Rates Application. The rates and riders, proposed to be effective on an interim basis for January 1, 2015, include an increase of approximately 10% to the distribution component of customer rates. This increase reflects a combined inflation and productivity factor of 1.49%, a K factor placeholder of approximately $69 million, which is 100% of the 2015 depreciation and return associated with the rate base resulting from the 2013 actual, and 2014 and 2015 forecast capital tracker expenditures as filed for in the May 2014 Capital Tracker Application, and a net refund of Y factor balances of approximately $1 million.
Caribbean Utilities
In October 2014 the ERA announced that Caribbean Utilities was the successful bidder for new generation capacity. Caribbean Utilities will develop and operate a new 39.7 MW diesel power plant including two 18.5 MW diesel generating units and a 2.7 MW waste heat recovery steam turbine. The project cost is estimated at US$85 million and the plant is expected to be commissioned no later than June 2016.
Significant Regulatory Proceedings
The following table summarizes ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's largest regulated utilities.
| Regulated Utility | Application/Proceeding | Filing Date | Expected Decision | ||
| Central Hudson | General Rate Application for mid-2015 | July 2014 | First half of 2015 | ||
| FortisAlberta | GCOC Proceeding 2013 and 2014 | Not applicable | Fourth quarter of 2014 | ||
| Capital Tracker Applications - 2013, 2014 and 2015 | May 2014 | First quarter of 2015 | |||
| 2015 Annual Rates Application | September 2014 | Fourth quarter of 2014 |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between September 30, 2014 and December 31, 2013.
| Significant Changes in the Consolidated Balance Sheets (Unaudited) between September 30, 2014 and December 31, 2013 | ||||||
Balance Sheet Account |
Increase Due to UNS Energy ($ millions) |
Other Increase/ (Decrease) ($ millions) |
Explanation for Other Increase/(Decrease) | |||
| Cash and cash equivalents | 62 | 324 | The increase was driven by cash on hand at FortisAlberta due to the issuance of $275 million unsecured debentures in September 2014, the net proceeds of which were used to repay $200 million of unsecured debentures that matured in October 2014. | |||
| Installment receivable | - | 1,201 | The increase relates to the final installment associated with the Convertible Debentures issued in January 2014. | |||
| Accounts receivable and other current assets | 219 | (169 | ) | The decrease was primarily due to the impact of a seasonal decrease in sales at the FortisBC Energy companies, Newfoundland Power, FortisBC Electric and Central Hudson. | ||
| Inventories | 148 | 56 | The increase was primarily due to the normal seasonal increase of gas in storage at the FortisBC Energy companies and the impact of higher natural gas commodity prices. | |||
| Regulatory assets - current and long-term | 282 | 140 | The increase was mainly due to an increase in the manufactured gas plant site remediation deferral at Central Hudson, an increase in regulatory deferred income taxes and the deferral of various other costs as permitted by the regulators. The increase was partially offset by a decrease in the deferral for employee future benefits. | |||
| Assets held for sale | - | (112 | ) | The decrease related to the sale of Griffith in March 2014. | ||
| Deferred income tax assets - current and long-term | 126 | 8 | The increase in deferred income tax assets was not significant. |
|||
| Other assets | 110 | 55 | The increase was mainly due to deferred costs at the Corporation associated with the Convertible Debentures issued in January 2014 to finance a portion of the acquisition of UNS Energy. | |||
| Utility capital assets | 4,094 | 555 | 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. | |||
| Intangible assets | 120 | (7 | ) | The decrease in intangible assets was not significant. | ||
| Goodwill | 1,547 | 30 | The increase in goodwill was not significant. | |||
| Short-term borrowings | - | 1,404 | The increase was driven by short-term borrowings at the Corporation to finance a portion of the acquisition of UNS Energy. Short-term borrowings at the FortisBC Energy companies to finance seasonal working capital requirements also contributed to the increase. | |||
| Accounts payable and other current liabilities | 291 | 36 | The increase in accounts payable and other current liabilities was not significant. | |||
| Regulatory liabilities - current and long-term | 471 | 27 | The increase in regulatory liabilities was not significant. | |||
| Long-term debt (including current portion) | 1,950 | 819 | The increase was driven by: (i) the issuance of long-term debt, including US$500 million unsecured notes at the Corporation, $275 million unsecured debentures at FortisAlberta and US$30 million unsecured notes at Central Hudson; (ii) higher credit facility borrowings, mainly at the Corporation to finance a portion of the acquisition of UNS Energy; and (iii) the impact of foreign exchange on the translation of US-dollar denominated debt. The increase was partially offset by regularly scheduled debt repayments. | |||
| Capital lease and finance obligations (including current portion) | 292 | 4 | The increase in capital lease and finance obligations was not significant. | |||
| Deferred income tax liabilities - current and long-term | 644 | 52 | The increase was driven by tax timing differences related mainly to capital expenditures at the regulated utilities. | |||
| Other liabilities | 197 | 62 | The increase was mainly due to an increase in the manufactured gas plant site remediation provision at Central Hudson. | |||
| Convertible debentures represented by installment receipts | - | 1,800 | The increase was due to the issuance of the Convertible Debentures in January 2014. | |||
| Shareholders' equity (before non-controlling interests) | - | 785 | The increase primarily related to: (i) the issuance of First Preference Shares, Series M in September 2014 for net after-tax proceeds of $591 million; (ii) net earnings attributable to common equity shareholders for the nine months ended September 30, 2014, less dividends declared on common shares; (iii) an increase in accumulated other comprehensive income associated with the translation of the Corporation's US-dollar denominated investments in subsidiaries; and (iv) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans. | |||
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the quarter and year-to-date periods ended September 30, 2014, as compared to the same periods in 2013, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows (Unaudited) | |||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |||||||
| Cash, Beginning of Period | 612 | 267 | 345 | 72 | 154 | (82 | ) | ||||||
| Cash Provided by (Used in): | |||||||||||||
| Operating Activities | 62 | 106 | (44 | ) | 648 | 666 | (18 | ) | |||||
| Investing Activities | (2,972 | ) | (253 | ) | (2,719 | ) | (3,370 | ) | (1,820 | ) | (1,550 | ) | |
| Financing Activities | 2,748 | 35 | 2,713 | 3,104 | 1,155 | 1,949 | |||||||
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | 8 | - | 8 | 4 | - | 4 | |||||||
| Cash, End of Period | 458 | 155 | 303 | 458 | 155 | 303 | |||||||
Operating Activities: Cash flow from operating activities was $44 million lower quarter over quarter. The decrease was primarily due to unfavourable changes in working capital mainly associated with accounts payable at Central Hudson, partially offset by favourable changes associated with accounts payable at FortisAlberta. Also contributing to lower cash flow from operating activities was unfavorable changes in long-term regulatory deferrals at the FortisBC Energy companies.
Cash flow from operating activities was $18 million lower year to date compared to the same period last year. The decrease was primarily due to unfavourable changes in working capital and unfavorable changes in long-term regulatory deferrals at the FortisBC Energy companies. Unfavorable changes in working capital were mainly associated with inventories, accounts payable and current regulatory deferrals at the FortisBC Energy companies and accounts payable at Newfoundland Power. The decrease was partially offset by higher cash earnings.
Investing Activities: Cash used in investing activities was $2,719 million higher quarter over quarter primarily due to the acquisition of UNS Energy in August 2014 for a net cash purchase price of $2,745 million. Capital expenditures at UNS Energy from the date of acquisition also contributed to the increase.
Cash used in investing activities was $1,550 million higher year to date compared to the same period last year. The increase was due to the acquisition of UNS Energy in August 2014, as discussed above for the quarter, compared to the acquisition of Central Hudson in June 2013 for a net cash purchase price of $1,019 million and FortisBC Electric's acquisition of the electrical utility assets from the City of Kelowna in March 2013 for approximately $55 million. Capital expenditures at UNS Energy from the date of acquisition and higher capital spending at the FortisBC Energy companies were partially offset by a decrease in capital expenditures at FortisAlberta and at the Waneta Expansion.
Financing Activities: Cash provided by financing activities was $2,713 million higher quarter over quarter primarily due to financing associated with the acquisition of UNS Energy in August 2014, including borrowings under the Corporation's Acquisition Credit Facilities. The increase was also due to higher proceeds from the issuance of preference shares and long-term debt, partially offset by higher repayments of long-term debt.
Cash provided by financing activities was $1,949 million higher year to date compared to the same period last year. The increase was primarily due to the financing of the UNS Energy acquisition, as discussed above for the quarter, and the proceeds of $599 million, or $561 million net of issue costs, from the first installment of the Convertible Debentures in January 2014 to finance a portion of the acquisition of UNS Energy, compared to financing associated with the acquisition of Central Hudson in June 2013, including borrowings under the Corporation's committed credit facility and the issuance of common shares. The increase was partially offset by higher repayments of long-term debt.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.
| Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited) | |||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |
| Central Hudson (1) | - | - | - | 33 | - | 33 | |
| FortisAlberta (2) | 274 | 150 | 124 | 274 | 150 | 124 | |
| Caribbean Utilities (3) | - | - | - | - | 51 | (51 | ) |
| Corporate (4) | 312 | - | 312 | 539 | - | 539 | |
| Total | 586 | 150 | 436 | 846 | 201 | 645 | |
| (1) | 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. |
| (2) | In September 2014 FortisAlberta issued $275 million senior unsecured debentures in a dual tranche of 10-year $150 million and 30-year $125 million at 3.30% and 4.11%, respectively. The net proceeds were used to repay $200 million 5.33% unsecured debentures that matured in October 2014, to finance capital expenditures and for general corporate purposes. In September 2013 FortisAlberta issued 30-year $150 million unsecured debentures at 4.85%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes. |
| (3) | In May 2013 Caribbean Utilities issued 15-year US$10 million 3.34% and 20-year US$40 million 3.54% senior unsecured notes. The net proceeds were used to repay short-term borrowings and to finance capital expenditures. |
| (4) | In June 2014 the Corporation issued US$213 million unsecured notes with terms to maturity ranging from 5 years to 30 years and coupon rates ranging from 2.92% to 4.88%. The weighted average term to maturity is approximately 9 years and the weighted average coupon rate is 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 years to 30 years and coupon rates ranging from 3.64% to 5.03%. The weighted average term to maturity is approximately 12 years and the weighted average coupon rate is 4.11%. Net proceeds were used to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis that matured in October 2014 and $125 million 5.56% unsecured debentures of a subsidiary that matured in September 2014, and for general corporate purposes. |
| Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | ||||||
| FortisBC Energy Companies | (1 | ) | (2 | ) | 1 | (4 | ) | (28 | ) | 24 | ||
| Central Hudson | - | - | - | (16 | ) | - | (16 | ) | ||||
| Newfoundland Power | (29 | ) | - | (29 | ) | (29 | ) | - | (29 | ) | ||
| Caribbean Utilities | - | - | - | (15 | ) | (17 | ) | 2 | ||||
| Corporate | (125 | ) | - | (125 | ) | (125 | ) | - | (125 | ) | ||
| Other | (2 | ) | (3 | ) | 1 | (12 | ) | (25 | ) | 13 | ||
| Total | (157 | ) | (5 | ) | (152 | ) | (201 | ) | (70 | ) | (131 | ) |
| Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited) | |||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||
| ($ millions) | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |||
| FortisAlberta | - | (94 | ) | 94 | (20 | ) | - | (20 | ) |
| FortisBC Electric | 36 | 11 | 25 | (43 | ) | 44 | (87 | ) | |
| Newfoundland Power | 33 | (20 | ) | 53 | 33 | 2 | 31 | ||
| Corporate | 257 | (84 | ) | 341 | 83 | 465 | (382 | ) | |
| Total | 326 | (187 | ) | 513 | 53 | 511 | (458 | ) | |
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.
Advances from non-controlling interests in the Waneta Expansion Limited Partnership ("Waneta Partnership") of $5 million and $22 million were received in the third quarter and year-to-date 2014, respectively, to finance capital spending related to the Waneta Expansion, compared to approximately $42 million received in the first half of 2013.
Proceeds from the issuance of common shares were $564 million lower year to date compared to the same period in 2013. The decrease was due to the issuance of 18.5 million common shares, as a result of the conversion of the Subscription Receipts on closing of the Central Hudson acquisition, for proceeds of approximately $567 million, net of after-tax expenses.
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. The net proceeds were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy.
In July 2013 Fortis issued 10 million First Preference shares, Series K for gross proceeds of $250 million. The net proceeds were used to redeem all of the Corporation's first Preference shares, Series C in July 2013 for $125 million, to repay a portion of credit facility borrowings and for other general corporate purposes.
Common share dividends paid in the third quarter of 2014 were $51 million, net of $18 million of dividends reinvested, compared to $49 million, net of $17 million of dividends reinvested, paid in the same quarter of 2013. Common share dividends paid year-to-date 2014 were $146 million net of $60 million in dividends reinvested, compared to $134 million, net of $51 million in dividends reinvested, paid year-to-date 2013. The dividend paid per common share for each of the first, second and third quarters of 2014 was $0.32 compared to $0.31 for each of the same quarters of 2013. The weighted average number of common shares outstanding for the third quarter and year-to-date 2014 was 215.6 million and 214.6 million, respectively, compared to 212.0 million and 199.1 million for the same periods in 2013.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at September 30, 2014, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2013 Annual MD&A and below, where applicable.
| Contractual Obligations (Unaudited) | Due | Due | |||||
| As at September 30, 2014 | within | Due in | Due in | Due in | Due in | after | |
| ($ millions) | Total | 1 year | year 2 | year 3 | year 4 | year 5 | 5 years |
| Long-term debt (1) | 9,973 | 887 | 594 | 288 | 137 | 322 | 7,745 |
| Interest obligations on long-term debt (1) | 8,584 | 493 | 461 | 431 | 428 | 417 | 6,354 |
| Capital lease and finance obligations (1) | 2,661 | 279 | 66 | 68 | 61 | 88 | 2,099 |
| Convertible debentures represented by installment receipts (2) | 1,800 | - | - | - | - | - | 1,800 |
| Interest obligations on convertible debentures represented by installment receipts (2) | 26 | 26 | - | - | - | - | - |
| Power purchase obligations (3) (4) | 895 | 233 | 169 | 123 | 101 | 77 | 192 |
| Renewable power purchase obligations (5) | 810 | 47 | 47 | 47 | 47 | 47 | 575 |
| Gas purchase contract obligations (6) | 521 | 426 | 40 | 18 | 12 | 12 | 13 |
| Capital cost | 542 | 19 | 21 | 19 | 21 | 19 | 443 |
| Long-term contracts - UNS Energy (7) | 611 | 119 | 118 | 110 | 72 | 52 | 140 |
| Renewable energy credit purchase agreements (8) | 139 | 8 | 10 | 10 | 10 | 10 | 91 |
| Purchase of Springerville common facilities (9) | 119 | - | - | 43 | - | - | 76 |
| Defined benefit pension funding contributions (10) | 162 | 49 | 42 | 16 | 8 | 8 | 39 |
| Waneta Partnership promissory note | 72 | - | - | - | - | - | 72 |
| Operating lease obligations | 58 | 10 | 9 | 7 | 7 | 7 | 18 |
| Joint-use asset and shared service agreements | 53 | 3 | 3 | 3 | 3 | 3 | 38 |
| Performance Share Unit Plan obligations | 17 | 2 | 5 | 10 | - | - | - |
| Other | 18 | 10 | 5 | - | - | 2 | 1 |
| Total | 27,061 | 2,611 | 1,590 | 1,193 | 907 | 1,064 | 19,696 |
| (1) | As a result of the acquisition of UNS Energy, the amount of the Corporation's commitments associated with long-term debt, interest obligations on long-term debt, and capital lease and finance obligations increased as at September 30, 2014. |
| (2) | 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 of the Corporation represented by installment receipts. For further information on the Convertible Debentures, refer to the "Significant Items" section of this MD&A. |
| (3) | Includes Central Hudson's contract to purchase 200 MW of installed capacity from May 2014 through April 2017, totalling approximately US$51 million as at September 30, 2014. Central Hudson's power purchase obligations also include an agreement to purchase available installed capacity from the Danskammer generating facility from October 2014 through August 2018, totalling approximately US$77 million as at September 30, 2014. |
| (4) | In May 2014 the BCUC approved FortisBC Electric's new power purchase agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh per year of associated energy for a 20-year term, effective July 1, 2014. |
| (5) | UNS Energy is party to 20-year long-term renewable power purchase agreements totalling approximately US$723 million as at September 30, 2014, which require UNS Energy to purchase 100% of the output of certain renewable energy generating facilities that have achieved commercial operation. UNS Energy has entered into additional long-term renewable power purchase agreements 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. |
| (6) | Gas purchase contract obligations are based on index prices and/or tariff rates as at September 30, 2014. |
| (7) | 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 totaling US$252 million, US$214 million and US$80 million, respectively, as at September 30, 2014. |
| (8) | UNS Energy is party to renewable energy credit purchase agreements, totalling approximately US$124 million as at September 30, 2014, 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) | Defined benefit pension funding contributions are based on estimates provided under the latest completed actuarial valuations, which generally provide funding estimates for a period of three to five years from the date of the valuations. The increase in contributions from that disclosed in the 2013 Annual MD&A reflects estimates from the actuarial valuations completed as at December 31, 2013, as well as the acquisition of UNS Energy. |
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2013 Annual MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electricity and gas distribution 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 45% equity, including preference shares, and 55% debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure (Unaudited) | As at | |||
| September 30, 2014 | December 31, 2013 | |||
| ($ millions) | (%) | ($ millions) | (%) | |
| Total debt and capital lease and finance obligations (net of cash) (1) | 13,599 | 66.7 | 7,716 | 56.2 |
| Preference shares | 1,820 | 8.9 | 1,229 | 9.0 |
| Common shareholders' equity | 4,966 | 24.4 | 4,772 | 34.8 |
| Total (2) | 20,385 | 100.0 | 13,717 | 100.0 |
| (1) | Includes long-term debt, capital lease and finance obligations, including current portion, convertible debentures represented by installment receipts and short-term borrowings, net of cash |
| (2) | Excludes amounts related to non-controlling interests |
The change in the capital structure was primarily due to the acquisition of UNS Energy, including: (i) drawings under the Corporation's Acquisition Credit Facilities to initially finance a portion of the acquisition; (ii) debt assumed upon acquisition; (iii) the Convertible Debentures issued in January 2014, of which the proceeds of the first installment were primarily used to finance a portion of the acquisition; and (iv) the issuance of First Preference Shares, Series M in September 2014 for net after-tax proceeds of $591 million, the proceeds of which were used to repay initial borrowings under the Acquisition Credit Facilities. The capital structure was also impacted by an increase in common shareholders' equity as a result of an increase in accumulated other comprehensive income, net earnings attributable to common equity shareholders for the nine months ended September 30, 2014, less dividends declared on common shares, and the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.
On October 28, 2014, net proceeds of approximately $1.165 billion from the final installment payment of the Convertible Debentures were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy. 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 a result, the Corporation's capital structure is comparable with December 31, 2013.
Excluding capital lease and finance obligations, the Corporation's capital structure as at September 30, 2014 was 65.4% debt, 9.3% preference shares and 25.3% common shareholders' equity (December 31, 2013 - 54.9% debt, 9.2% preference shares and 35.9% common shareholders' equity).
CREDIT RATINGS
The Corporation's credit ratings are as follows:
| Standard & Poor's ("S&P") | A- / Stable (long-term corporate and unsecured debt credit rating) |
| DBRS | A(low) / Under Review - Developing Implications (unsecured debt credit rating) |
The above-noted credit ratings reflect the Corporation's 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 low levels of debt at the holding company level. In December 2013, after the announcement by Fortis that it had entered into an agreement to acquire UNS Energy, DBRS placed the Corporation's credit rating under review with developing implications and S&P revised its outlook on the Corporation to negative from stable. In October 2014, following the conversion of substantially all of Convertible Debentures into common shares, S&P revised its outlook on the Corporation to stable.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $875 million in gross consolidated capital expenditures by segment year-to-date 2014 is provided in the following table.
| Gross Consolidated Capital Expenditures (Unaudited) (1) |
| Year-to-Date September 30, 2014 |
| ($ millions) |
| Regulated Utilities | Non-Regulated | |||||||||
| FortisBC | Total | |||||||||
| UNS | Central | Energy | Fortis | FortisBC | Eastern | Electric | Regulated | Fortis | Non- | |
| Energy | Hudson | Companies | Alberta | Electric | Canadian | Caribbean | Utilities | Generation | Utility | Total |
| 45 | 84 | 200 | 244 | 58 | 105 | 42 | 778 | 70 | 27 | 875 |
| (1) | Relates to cash payments to acquire or 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 allowance for funds used during construction. |
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2014 are forecast to be approximately $1.8 billion. This represents an increase of approximately $400 million from the original 2014 forecast disclosed in the 2013 Annual MD&A. The increase is driven by forecast capital spending of approximately $450 million (US$400 million) at UNS Energy from the date of acquisition. In December 2014 UNS Energy is expected to purchase Unit 3 of the Gila River generating station, which is a gas-fired combined-cycle unit with a capacity of 550 MW, for US$219 million. Also contributing to the increase is higher forecast capital spending at the FortisBC Energy companies, partially offset by lower forecast capital spending at FortisAlberta and the Waneta Expansion. The increase in capital spending at the FortisBC Energy companies primarily relates to the timing of expenditures associated with the Tilbury liquefied natural gas ("LNG") facility expansion. At FortisAlberta, required contributions toward transmission projects, as approved by the regulator, are lower than originally forecast. The forecast decrease in capital spending at the Waneta Expansion is primarily due to the timing of payments.
In October 2014 FortisBC started construction of its Tilbury LNG facility expansion in British Columbia. The Tilbury expansion will be included in regulated rate base and is estimated to cost approximately $400 million. It will include a second LNG tank and a new liquefier, both to be in service in the second half of 2016. FortisBC is pursuing additional LNG investment opportunities, including a further $450 million expansion of Tilbury and a $600 million pipeline expansion for the proposed Woodfibre LNG site in British Columbia. These additional $1 billion of investment opportunities are not included in the Corporation's capital expenditure forecast.
Construction of the $900 million Waneta Expansion is ongoing, with an additional $69 million invested year-to-date 2014. Approximately $648 million has been invested in the Waneta Expansion since construction began late in 2010. Key construction activities year-to-date 2014 were focused on civil construction and equipment installation, assembly and testing. Concrete work at the intake structure, civil construction of one of two power tunnel transitions and excavation of the tailrace channel were substantially completed. Forming and casting of concrete for the second power tunnel transition and removal of the tailrace rock plug continued. Equipment installation and assembly continued with the turbine and generator components and powerhouse mechanical and electrical auxiliary systems. Testing and commissioning was performed on various components and systems in preparation for turbine and generator commissioning scheduled for late 2014 and early 2015.
Over the five-year period 2014 through 2018, gross consolidated capital expenditures are expected to exceed $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 37% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 33% at Regulated Electric & Gas Utilities - United States; 22% at Canadian Regulated Gas Utilities; 5% at Caribbean Regulated Electric Utilities; and the remaining 3% 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: 46% for sustaining capital expenditures, 37% to meet customer growth, and 17% for facilities, equipment, vehicles, information technology and other assets.
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. The subsidiaries expect to be able to source the cash required to fund their 2014 capital expenditure programs.
As at September 30, 2014, management expects consolidated long-term debt maturities and repayments to average approximately $340 million annually over the next five years, excluding long-term credit facility borrowings. The combination of available credit facilities and relatively low annual debt maturities and repayments beyond 2014 will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
Fortis and its subsidiaries were compliant with debt covenants as at September 30, 2014 and are expected to remain compliant throughout 2014.
CREDIT FACILITIES
As at September 30, 2014, the Corporation and its subsidiaries had consolidated credit facilities of approximately $4.9 billion, of which $2.6 billion was unused, including $999 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 25% of these facilities. Approximately $4.6 billion of the total credit facilities are committed facilities with maturities ranging from 2015 through 2019.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities (Unaudited) | As at | |||||||||
| Regulated | Non- | Corporate | September 30, | December 31, | ||||||
| ($ millions) | Utilities | Regulated | and Other | 2014 | 2013 | |||||
| Total credit facilities | 1,986 | 13 | 2,900 | 4,899 | 2,695 | |||||
| Credit facilities utilized: | ||||||||||
| Short-term borrowings | (246 | ) | - | (1,318 | ) | (1,564 | ) | (160 | ) | |
| Long-term debt | (224 | ) | - | (300 | ) | (524 | ) | (313 | ) | |
| Letters of credit outstanding | (175 | ) | - | (1 | ) | (176 | ) | (66 | ) | |
| Credit facilities unused | 1,341 | 13 | 1,281 | 2,635 | 2,156 | |||||
As at September 30, 2014 and December 31, 2013, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.
In April 2014 FortisBC Electric extended the maturity of its $150 million unsecured committed revolving credit facility, with $100 million now maturing in May 2017 and $50 million now maturing in April 2015.
In July 2014 FEI, FortisAlberta and Newfoundland Power amended their $500 million, $250 million and $100 million, respectively, committed revolving credit facilities, resulting in extensions to their maturity dates to August 2016, August 2019 and August 2019, respectively, from August 2015, August 2018 and August 2017, respectively.
As at September 30, 2014, UNS Energy had a US$300 million ($336 million) unsecured committed revolving credit facility and a US$82 million ($92 million) letter of credit facility, both maturing in November 2016.
As at September 30, 2014, Corporate and Other credit facilities consisted of the following: (i) the Corporation's $1 billion unsecured committed revolving credit facility, maturing in July 2018; (ii) the Corporation's Acquisition Credit Facilities, consisting of $1.118 billion remaining under the short-term bridge facility maturing in May 2015, and $300 million remaining under the medium-term bridge facility maturing in August 2016; (iii) a new $200 million uncommitted non-revolving unsecured demand term credit facility at the Corporation, repayable in full in November 2014; (iv) a US$100 million ($112 million) unsecured committed revolving credit facility at CH Energy Group, maturing in October 2015; (v) a US$125 million ($140 million) unsecured committed revolving credit facility at UNS Energy Corporation, maturing in November 2016; and (vi) a $30 million unsecured committed revolving credit facility at FHI maturing in April 2015.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| Financial Instruments (Unaudited) | As at | |||||||
| September 30, 2014 | December 31, 2013 | |||||||
| Asset (Liability) | Carrying | Estimated | Carrying | Estimated | ||||
| ($ millions) | Value | Fair Value | Value | Fair Value | ||||
| Investment in lease equity | 40 | 29 | - | - | ||||
| Waneta Partnership promissory note | (52 | ) | (54 | ) | (50 | ) | (50 | ) |
| Long-term debt, including current portion | (9,973 | ) | (11,427 | ) | (7,204 | ) | (8,084 | ) |
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 fair value of the investment in lease equity is determined based on an estimated price at which an investor would realize a target internal rate of return and assumes a residual value based on an appraisal of Springerville generating station Unit 1 conducted in 2011. No impairment has been recorded as TEP expects to recover the full carrying value of the investment in retail rates.
The Financial Instruments table above excludes the long-term other asset associated with the Corporation's expropriated investment in Belize Electricity. Due to uncertainty in the ultimate amount and ability of the Government of Belize ("GOB") to pay appropriate fair value compensation owing to Fortis for the expropriation of Belize Electricity, the Corporation has recorded the book value of the expropriated investment, including foreign exchange impacts, in long-term other assets, which totalled approximately $113 million as at September 30, 2014 (December 31, 2013 - $108 million).
Risk Management: The Corporation's earnings from, and net investment 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, Belize Electric Company Limited and FortisUS Energy Corporation is the US dollar.
As at September 30, 2014, the Corporation's corporately issued US$1,375 million (December 31, 2013 - US$1,033 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at September 30, 2014, the Corporation had approximately US$2,767 million (December 31, 2013 - US$560 million) in foreign net investments remaining to be hedged. The Corporation's US dollar-denominated foreign net investments as at September 30, 2014 were significantly impacted by the UNS Energy acquisition, which was substantially financed through Acquisition Credit Facilities denominated in Canadian dollars. 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 in 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 in other comprehensive income.
As a result of the acquisition of UNS Energy, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, including UNS Energy, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative-to-Canadian dollar exchange rate would increase or decrease earnings per common share of Fortis by approximately 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.
Effective June 20, 2011, the Corporation's asset associated with its expropriated investment in Belize Electricity does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, foreign exchange gains and losses on the translation of the long-term other asset associated with Belize Electricity are recognized in earnings. The Corporation recognized in earnings a foreign exchange gain of approximately $5 million for the three and nine months ended September 30, 2014 (foreign exchange loss of $2 million for the three months ended and a foreign exchange gain of $3 million for the nine months ended September 30, 2013).
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel, electricity and natural gas prices through the use of derivative instruments. The Corporation does not hold or issue derivative instruments for trading purposes and generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges. As at September 30, 2014, the Corporation's derivative instruments primarily consisted of electricity swap contracts, electricity power contracts, gas swap and option contracts, and gas purchase contract premiums. Central Hudson holds electricity swap contracts and gas swap and option contracts. The FortisBC Energy companies hold gas swap and option contracts and gas purchase contract premiums. UNS Energy holds electricity power contracts, gas swap and option contracts and gas purchase swap contracts. UNS Energy holds both energy contracts and interest rate swaps as cash flow hedges.
The following table summarizes the Corporation's derivative instruments.
| Derivative Instruments (Unaudited) | As at | |||||||
| Asset (Liability) |
Maturity |
Number of Contracts |
Volume (1) |
September 30, 2014 Net Carrying Value (2) (3) ($ millions) |
|
December 31, 2013 Net Carrying Value (2) ($ millions) |
|
|
| Electricity swap contracts | 2017 | 10 | 2,511 | 22 | 10 | |||
| Electricity power contracts | 2015 | 35 | 1,407 | (2 | ) | - | ||
| Natural gas derivatives: | ||||||||
| Gas swaps and option contracts | 2017 | 201 | 71 | (5 | ) | (13 | ) | |
| Gas purchase contract premiums | 2015 | 79 | 99 | (3 | ) | (2 | ) | |
| Energy contracts - cash flow hedges | 2015 | 1 | 59 | (1 | ) | - | ||
| Interest rate swaps - cash flow hedges | 2020 | 2 | n/a | (5 | ) | - | ||
| (1) | The electricity contracts are in GWh and natural gas derivatives are in PJ. |
| (2) | Carrying value is estimated fair value. |
| (3) | The Corporation has elected gross presentation for the derivative contracts under master netting agreements as reported in Note 20 of the unaudited interim consolidated financial statements. The derivative balances in the above table are presented based on net position by contract type. The positions on a gross basis are as follows: electricity swap contracts ($23 million asset and $1 million liability); electricity power contracts ($2 million asset and $4 million liability); gas swap and option contracts ($4 million asset and $9 million liability); gas purchase contract premiums ($3 million liability); energy contracts - cash flow hedges ($1 million liability); and interest rate swaps - cash flow hedges ($5 million liability). |
The electricity swap contracts and natural gas derivatives are used by Central Hudson to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair values of the electricity swap contracts and natural gas derivatives were calculated using forward pricing provided by independent third parties.
The natural gas derivatives are used by the FortisBC Energy companies 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.
The price risk-management strategy of the FortisBC Energy companies aims to improve the likelihood that natural gas prices remain competitive, mitigate gas price volatility on customer rates and reduce the risk of regional price discrepancies. As directed by the regulator, the FortisBC Energy companies have suspended their commodity hedging activities, with the exception of certain limited swaps as permitted by the regulator. The existing hedging contracts will continue in effect through to their maturities and the FortisBC Energy companies' ability to fully recover the cost of gas in customer rates remains unchanged. Any differences between the cost of natural gas purchased and the price of natural gas included in customer rates are recorded as regulatory deferrals and are recovered from, or refunded to, customers in future rates, subject to regulatory approval.
Electricity and natural gas derivatives are used by UNS Energy to reduce its exposure to energy price risk associated with gas and purchased power requirements. UNS Energy primarily applies the market approach for recurring 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 options are 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.
The fair values of the derivative contracts are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
The changes in the fair values of the derivative contracts are primarily deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. The fair value of the derivative contracts is recorded in accounts receivable and other current assets, other long-term assets, accounts payable and other current liabilities, and other long-term liabilities as at September 30, 2014 and December 31, 2013.
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.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $176 million as at September 30, 2014 (December 31, 2013 - $66 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. The increase in letters of credit outstanding is primarily a result of the acquisition of UNS Energy.
BUSINESS RISK MANAGEMENT
Year-to-date 2014, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2013 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable. In addition, the Corporation is subject to certain business risks as a result of the acquisition of UNS Energy, which are discussed below.
Regulatory Risk: For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A. A description of regulation at UNS Energy is also included in the "Regulated Electric & Gas Utilities - United States" section of this MD&A.
Completion of the Acquisition of UNS Energy: As a result of the closing of the UNS Energy acquisition on August 15, 2014, the risks associated with the completion of the transaction are no longer applicable, except as noted below.
As a result of the acquisition of UNS Energy, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, including UNS Energy, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative-to-Canadian dollar exchange rate would increase or decrease earnings per common share of Fortis by approximately 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.
Risks Associated with UNS Energy: UNS Energy is exposed to certain business risks as part of its ongoing operations as regulated electric and gas utilities. Certain of these risks, including regulation, are similar in nature to business risks associated with the Corporation's other regulated utilities. There are, however, risks that are specific to the operations of UNS Energy, the most significant of which are detailed below.
Local Economic Conditions
The business of UNS Energy is concentrated in the State of Arizona. In recent years economic conditions in the State of 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 the State of 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, adversely affecting UNS Energy's results of operations, net earnings and cash flows.
Technology Developments in Distributed Generation 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 UNS Energy's 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. UNS Energy is 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 or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy efficiency and more energy efficient appliances and equipment. Advances in these, or other technologies, could reduce the cost of producing electricity or make the existing facilities of UNS Energy less economical. In addition, advances in such technologies could reduce electrical demand, which could negatively impact the results of operations, net earnings and cash flows of TEP and UNS Electric.
Environmental Laws and Regulations
Numerous federal, state and local environmental laws and regulations in the United States and the State of Arizona affect present and future operations of UNS Energy's regulated utility subsidiaries. Those laws and regulations include rules regarding air emissions, water use, wastewater discharges, solid waste, hazardous waste and management of coal combustion residuals.
These laws and regulations can contribute to higher capital, operating and other costs, particularly with regard to compliance efforts focused on existing power plants and new compliance standards related to new and existing power plants. Existing environmental laws and regulations may be revised or new environmental laws and regulations may be adopted or become applicable to the facilities and operations of the UNS Utilities. Increased compliance costs or additional operating restrictions from revised or additional regulation could have an adverse effect on the results of operations of UNS Energy. The utilities would request that additional costs resulting from environmental laws and regulation be recovered from customers through regulated rates.
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. 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 recovers final mine reclamation costs through regulator-approved mechanisms as costs are paid to the coal suppliers.
In June 2014 the United States Environmental Protection Agency (the "EPA") proposed carbon emission standards to reduce greenhouse gas emissions from existing power plants. EPA's proposal for Arizona would result in a significant shift in generation from coal to natural gas and renewables and may require some or all of Arizona coal-fired generation plants to cease operation by 2020. The EPA is scheduled to finalize those standards by June 2015. These proposed regulations would, if adopted in the form proposed, result in a change in the composition of TEP's generating fleet. As at September 30, 2014, approximately 70% of TEP's generating capacity is fuelled by coal. The final rule issued by the EPA could significantly impair the ability to operate certain of TEP's coal-fired generation plants on an economically viable basis or at all. A substantial change in TEP's generation portfolio could result in increased cost of operations and/or additional capital investments. The impact of final regulations to address global climate change will depend on the specific terms of those measures and cannot be determined at this time.
Stranded Assets
UNS Energy's coal-fired generating stations may be required to be closed before the end of their useful lives in response to recent or future changes in environmental regulation, including potential regulation relating to greenhouse gas emissions. If any of the coal-fired generation plants, or coal handling facilities, from which TEP obtains power are closed prior to the end of their useful life, TEP 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 of such generating stations may force TEP to incur higher costs for replacement capacity and energy. TEP may not be permitted recovery of these costs in the rates it charges its customers.
Expropriation of Shares in Belize Electricity: On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. Consequent to the deprivation of control over the operations of the utility, the Corporation discontinued the consolidation method of accounting for Belize Electricity, as of June 20, 2011, and classified the book value, including foreign exchange impacts, of the expropriated investment as a long-term other asset on the consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to challenging the constitutionality of the expropriation of the Corporation's investment in Belize Electricity. Fortis commissioned an independent valuation of its expropriated investment and submitted its claim for compensation to the GOB in November 2011. The book value of the long-term other asset is below fair value as at the date of expropriation as determined by independent valuators. The GOB also commissioned a valuation of Belize Electricity, which is significantly lower than both the fair value determined under the Corporation's valuation and the book value of the long-term other asset.
In July 2012 the Belize Supreme Court dismissed the Corporation's claim of October 2011. Also in July 2012, Fortis filed its appeal of the above-noted trial judgment in the Belize Court of Appeal. The appeal was heard in October 2012 and a decision was rendered by the Belize Court of Appeal in May 2014. The two Belizean judges found in favour of the GOB; however, the third judge delivered a strong dissenting opinion concluding that the expropriation was contrary to the Belize Constitution. An appeal of the decision to the Caribbean Court of Justice, the final court for appeals arising in Belize, was filed in June 2014 and Fortis filed its written submission for appeal in October 2014. A hearing is scheduled for December 2014.
Fortis believes it has a strong, well-positioned case supporting the unconstitutionality of the expropriation. There exists, however, a possibility that the outcome of the litigation may be unfavourable to the Corporation and the amount of compensation to be paid to Fortis could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. The book value was $113 million, including foreign exchange impacts, as at September 30, 2014 (December 31, 2013 - $108 million). If the expropriation is held to be unconstitutional, it is not determinable at this time as to the nature of the relief that would be awarded to Fortis; for example: (i) ordering return of the shares to Fortis and/or award of damages; or (ii) ordering compensation to be paid to Fortis for the unconstitutional expropriation of the shares and/or award of damages. Based on presently available information, the $113 million long-term other asset is not deemed impaired as at September 30, 2014. Fortis will continue to assess for impairment each reporting period based on evaluating the outcomes of court proceedings and/or compensation settlement negotiations. As well as continuing the constitutional challenge of the expropriation, Fortis is also pursuing alternative options for obtaining fair compensation, including compensation under the Belize/United Kingdom Bilateral Investment Treaty.
Capital Resources and Liquidity Risk - Credit Ratings: The Corporation's credit ratings were affirmed by S&P in October 2014 and DBRS in February 2014. Year-to-date 2014, the following changes were made to the credit ratings of the Corporation's utilities: (i) Moody's Investor Service ("Moody's") upgraded Central Hudson to 'A2' from 'A3' with a stable outlook in January 2014; (ii) DBRS confirmed FortisAlberta's credit rating at 'A(low)' and changed the trend to positive from stable in February 2014; (iii) S&P confirmed Maritime Electric's and Caribbean Utilities' credit ratings at 'A' and 'A-', respectively, both with a negative outlook in May 2014; (iv) in June 2014 Moody's affirmed the long-term credit ratings of FEI, FEVI and FortisBC Electric and changed the ratings outlook to stable from negative; (v) Fitch Ratings confirmed Central Hudson's credit rating at 'A' and revised the outlook to negative from stable in July 2014; (vi) in August 2014 Moody's affirmed the credit ratings of UNS Energy at 'Baa2' and TEP, UNS Electric and UNS Gas at 'Baa1' and changed the ratings outlook to positive; and (vii) in October 2014, following the conversion of substantially all of the Convertible Debentures into common shares, S&P revised its outlook on FortisAlberta, Maritime Electric and Caribbean Utilities to stable and upgraded TEP's credit rating to 'BBB+' from 'BBB'. In addition, in July 2014 the Turks and Caicos Islands received its first sovereign credit rating of 'BBB+' from S&P and in September 2014 FortisTCI received its first credit rating of 'BBB' from S&P, with a stable outlook.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at September 30, 2014, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,258 million, up $596 million or 36%, from $1,662 million as at December 31, 2013. Of the increase from December 31, 2013, approximately $399 million, or 67%, was due to the acquisition of UNS Energy.
Labour Relations: The collective agreements between the FortisBC Energy companies and Canadian Office and Professional Employees Union ("COPE") and FortisBC Electric and COPE representing customer service employees expired on March 31, 2014. The collective agreements have been renewed for three-year periods expiring on March 31, 2017.
The collective agreement between FortisBC Electric and International Brotherhood of Electrical Workers ("IBEW") expired on January 31, 2013. In December 2013, following a labour disruption, the IBEW and FortisBC Electric agreed to binding interest arbitration. The arbitration process was completed in June 2014 and the arbitrator's decision was received in November 2014, resulting in the collective agreement expiring in January 2018.
The collective agreement between the FortisBC Energy companies and IBEW expires on March 31, 2015. IBEW represents employees in specified occupations in the areas of transmission and distribution. In October 2014 the collective agreement was renewed and now expires on March 31, 2019.
Power Supply Contracts: In May 2014 the BCUC approved FortisBC Electric's new power purchase agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh per year of associated energy for a 20-year term, effective July 1, 2014.
FortisBC Electric has a power-supply sale agreement with BC Hydro for the sale of electricity generated from its non-regulated Walden Power Partnership hydroelectric generating facility, which has a net book value of approximately $10 million as at September 30, 2014. Subject to a five-month notice of termination by BC Hydro, which has not yet been issued, this agreement could expire. Accordingly, the Company is exposed to the risk that it will not be able to sell the power from this facility beyond the expiry of the current contract on similar terms.
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2014, as approved in its Multi-Year PBR Plan, FEI began depreciating utility capital assets and amortizing intangible assets the year after the assets are available for use. Prior to January 1, 2014, depreciation and amortization commenced the month after the assets were available for use.
The new US GAAP accounting pronouncements that are applicable to, and were adopted by, Fortis, effective January 1, 2014, are described as follows.
Obligations Resulting from Joint and Several Liability Arrangements
The Corporation adopted Accounting Standards Update ("ASU") No. 2013-04 Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The above-noted ASU was applied retrospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
Parent's Accounting for the Cumulative Translation Adjustment
The Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 830, Foreign Currency Matters - Parent's Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity, as outlined in ASU No. 2013-05. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
Presentation of an Unrecognized Tax Benefit
The Corporation adopted the amendments to ASC Topic 740, Income Taxes - Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, as outlined in ASU No. 2013-11. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
FUTURE ACCOUNTING PRONOUNCEMENTS
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
In April 2014 the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in this update change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. This update is effective for annual and interim periods beginning on or after December 15, 2014 and is to be applied prospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
Revenue from Contracts with Customers
In May 2014 FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. 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 is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. Early adoption is not permitted. Fortis is assessing the impact that the adoption of this standard will have on its consolidated financial statements.
Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period
In June 2014 FASB issued ASU No. 2014-12, 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 amendments in this update are intended to resolve 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. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied prospectively or retrospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern
In August 2014 FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The amendments in this update are intended to provide guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning on or after December 15, 2016. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the nine months ended September 30, 2014 from those disclosed in the 2013 Annual MD&A. However, the magnitude of the accounting estimates has increased due to the acquisition of UNS Energy.
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.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed settlement agreement with counsel to plaintiff shareholders pertaining to several complaints, which named Fortis and other defendants, which were filed in, or transferred to, the Supreme Court of the State of New York, County of New York, relating to the acquisition of CH Energy Group by Fortis. The complaints generally alleged that the directors of CH Energy Group breached their fiduciary duties in connection with the acquisition and that CH Energy Group, Fortis, FortisUS Inc. and Cascade Acquisition Sub Inc. aided and abetted that breach. The settlement agreement was subject to court approval. In June 2014 the Supreme Court of the State of New York, County of New York issued an Order and Final Judgment approving the settlement agreement thereby concluding the proceedings.
Following the announcement of the acquisition of UNS Energy on December 11, 2013, four complaints which named Fortis and other defendants were filed in the Superior Court of the State of Arizona ("Superior Court") in and for the County of Pima and one claim in the United States District Court in and for the District of Arizona, challenging the acquisition. The complaints generally allege that the directors of UNS Energy breached their fiduciary duties in connection with the acquisition and that UNS Energy, Fortis, FortisUS Inc., and Color Acquisition Sub Inc. aided and abetted that breach. In March 2014 two of the four complaints filed in the Superior Court were dismissed by the plaintiffs and counsel for the parties in the two actions remaining in the Superior Court executed a Memorandum of Understanding recording an agreement-in-principle on the structure of a settlement to be proposed to the Superior Court for approval following closing of the acquisition. In April 2014 the complaint filed in the United States District Court was dismissed by the plaintiff. The outcome of these lawsuits cannot be predicted with any certainty 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 British Columbia Supreme Court ("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.
FortisBC Energy Companies
FEI was the plaintiff in a B.C. Supreme Court action against the City of Surrey ("Surrey") in which FEI sought the court's determination on the manner in which costs related to the relocation of a natural gas transmission pipeline would be shared between the Company and Surrey. The relocation was required due to the development and expansion of Surrey's transportation infrastructure. FEI claimed that the parties had an agreement that dealt with the allocation of costs. Surrey advanced counterclaims, including an allegation that FEI breached the agreement and that Surrey suffered damages as a result. In December 2013 the court issued a decision ordering FEI and Surrey to share equally the cost of the pipeline relocation. The court also decided that Surrey was successful in its counterclaim that FEI breached the agreement. The amount of damages that may be awarded to Surrey at a subsequent hearing cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices Code and negligence relating to a forest fire near Vaseux Lake in 2003, prior to the acquisition of FortisBC Electric by Fortis, and has filed and served a writ and statement of claim against FortisBC Electric dated August 2, 2005. In September 2014 a settlement was reached on the matter and a full release and consent dismissal of the action is pending. As FortisBC Electric was insured against this claim, the settlement is not expected to impact the Corporation's consolidated net earnings.
The Government of British Columbia filed a claim in the B.C. 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 not been served, the Company has retained counsel and has notified its insurers. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
Central Hudson
Former Manufactured Gas Plant ("MGP") Facilities
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 September 30, 2014, an obligation of US$105 million was recognized in respect of MGP remediation and, based upon cost model analysis completed in 2012, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$152 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.
Asbestos Litigation
Prior to and after the acquisition of CH Energy Group, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,347 asbestos cases have been raised, 1,172 remained pending as at September 30, 2014. Of the cases no longer pending against Central Hudson, 2,020 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 155 cases. The Company is presently unable to assess the validity of the remaining 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.
UNS Energy
San Juan Generating Station
San Juan Coal Company ("SJCC") operates an underground coal mine in an area where certain gas producers have oil and gas leases with the Government of the United States, the State of New Mexico, and private parties. These gas producers allege that SJCC's underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan generating station, which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. The Company cannot reasonably estimate the impact of any future claims by these gas producers and, accordingly, no amount has been accrued in the consolidated financial statements.
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$44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The mine reclamation liability recorded as at September 30, 2014 was US$21 million, and represents the present value of the estimated future liability.
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements' terms.
TEP is permitted to fully recover these costs from customers and, accordingly, these costs are deferred as a regulatory asset.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended December 31, 2012 through September 30, 2014. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results | Net Earnings | |||
| (Unaudited) | Attributable to | |||
| Common Equity | ||||
| Revenue | Shareholders | Earnings per Common Share | ||
| Quarter Ended | ($ millions) | ($ millions) | Basic ($) | Diluted ($) |
| September 30, 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 |
| December 31, 2013 | 1,229 | 100 | 0.47 | 0.47 |
| September 30, 2013 | 915 | 48 | 0.23 | 0.23 |
| June 30, 2013 | 790 | 54 | 0.28 | 0.28 |
| March 31, 2013 | 1,113 | 151 | 0.79 | 0.76 |
| December 31, 2012 | 999 | 87 | 0.46 | 0.45 |
The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions and associated acquisition-related expenses, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the commodity cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the FortisBC Energy companies 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.
September 2014/September 2013: Net earnings attributable to common equity shareholders were $14 million, or $0.06 per common share, for the third quarter of 2014 compared to earnings of $48 million, or $0.23 per common share, for the third quarter of 2013. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
June 2014/June 2013: Net earnings attributable to common equity shareholders were $47 million, or $0.22 per common share, for the second quarter of 2014 compared to earnings of $54 million, or $0.28 per common share, for the second quarter of 2013. Earnings for the second quarter were reduced by $13 million in after-tax interest expense associated with the Convertible Debentures. Earnings for the second quarter of 2013 were reduced by $32 million, due to acquisition-related expenses and customer and community benefits offered to obtain regulatory approval of the acquisition of Central Hudson. Earnings for the second quarter of 2013 were favourably impacted by an income tax recovery of $25 million, due to the enactment of higher deductions associated with Part VI.1 tax on the Corporation's preference share dividends. Excluding the above-noted items, earnings for the second quarter of 2014 were consistent with the same period last year. Corporate and Other expenses were higher quarter over quarter due to unfavourable foreign exchange impacts, the impact of the release of income tax provisions in the second quarter of 2013, increased finance charges associated with the acquisition of Central Hudson and higher operating expenses, partially offset by a higher income tax recovery and interest income. The decrease in earnings was partially offset by: (i) earnings contribution from Central Hudson; (ii) the timing of the recognition of the regulatory decision on the first stage of the GCOC Proceeding in British Columbia at the FortisBC Energy companies and FortisBC Electric in 2013; (iii) electricity sales growth at the Caribbean Regulated Electric Utilities; and (iv) increased non-regulated hydroelectric generation in Belize.
March 2014/March 2013: Net earnings attributable to common equity shareholders were $143 million, or $0.67 per common share, for the first quarter of 2014 compared to earnings of $151 million, or $0.79 per common share, for the first quarter of 2013. Earnings for the first quarter of 2014 included $5 million from discontinued operations associated with Griffith and were reduced by $11 million in after-tax interest expense associated with the convertible debentures. Earnings for the first quarter of 2013 included an approximate $22 million extraordinary gain associated with the Exploits Partnership. Excluding the above-noted items, earnings for the first quarter of 2014 were favourably impacted by: (i) contribution of $18 million from Central Hudson; (ii) increased non-regulated hydroelectric generation in Belize; (iii) regulator-approved adjustments at Newfoundland Power, which impacted the timing of quarterly earnings; and (iv) electricity sales growth at the Caribbean Regulated Electric Utilities. The increases were partially offset by lower earnings at the FortisBC Energy companies and higher Corporate and Other expenses. The first stage of the GCOC Proceeding in British Columbia reduced the allowed ROE and common equity component of capital structure for the benchmark utility, FEI, effective January 1, 2013; however, the impact of this regulatory decision was not recognized until the second quarter of 2013, when the decision was received.
December 2013/December 2012: Net earnings attributable to common equity shareholders were $100 million, or $0.47 per common share, for the fourth quarter of 2013 compared to earnings of $87 million, or $0.46 per common share, for the fourth quarter of 2012. Results for the fourth quarter of 2013 were impacted by the acquisition of CH Energy Group, including contribution of $11 million from Central Hudson and a net loss of approximately $2 million at the non-regulated operations. Earnings for the fourth quarter of 2013 were also favourably impacted by: (i) increased non-regulated hydroelectric generation in Belize, partially offset by income tax expenses associated with the Exploits Partnership; (ii) higher earnings at Caribbean Regulated Electric Utilities, driven by the capitalization of overhead costs at Fortis Turks and Caicos; (iii) higher earnings at the FortisBC Energy companies and FortisBC Electric, mainly due to lower-than-expected finance charges and rate base growth, partially offset by decreases in the allowed ROEs for each of the utilities and the common equity component of capital structure at FEI; and (iv) a gain on the sale of land at Newfoundland Power. The increase was partially offset by lower earnings at FortisAlberta and FortisOntario. The timing of depreciation and certain operating expenses, and lower net transmission revenue at FortisAlberta were partially offset by rate base growth and growth in the number of customers. At FortisOntario, the decrease was primarily due to the impact of the cumulative return adjustment on smart meter investments in 2012. Corporate and Other expenses were comparable quarter over quarter.
OUTLOOK
Fortis is a leading electric and gas utility owner and operator in North America, currently serving more than 3 million customers in its utility businesses. The Corporation's focus continues to be on the low-risk, regulated utility businesses and long-term contracted energy infrastructure.
In October 2014 the Corporation commenced a review of strategic options for its hotel and commercial real estate business, operating as Fortis Properties. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. This review process is expected to continue through the balance of 2014 and into 2015. Fortis Properties currently comprises approximately 3% of the Corporation's total assets.
Over the five-year period 2014 through 2018, the Corporation's capital program is expected to exceed $9 billion. Following a decade of strong growth, primarily achieved through acquisitions, Fortis is now entering a period of significant organic growth, with a four-year compound annual growth rate in rate base through 2018 estimated at 7%. Fortis is also pursuing significant natural gas investment opportunities, particularly in British Columbia. Two new regulated projects - further expansion of the Tilbury LNG facility and the Woodfibre pipeline expansion, could increase the four-year compound annual growth rate in rate base through 2018 to 8.5%.
SUBSEQUENT EVENT
On October 28, 2014, the Corporation received gross proceeds of approximately $1.2 billion, or $1.165 billion net of issue costs, from the final installment payment of the Convertible Debentures. The net proceeds of the final installment were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy. 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. For further information on the Convertible Debentures, refer to the "Significant Items" section of this MD&A.
OUTSTANDING SHARE DATA
As at November 6, 2014, the Corporation had issued and outstanding approximately 274.7 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; 10.0 million First Preference Shares, Series H; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether or not such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options, First Preference Shares, Series E and Convertible Debentures were converted as at November 6, 2014 is as follows.
| Conversion of Securities into Common Shares (Unaudited) | |
| As at November 6, 2014 | Number of |
| Common Shares | |
| Security | (millions) |
| Stock Options | 5.3 |
| First Preference Shares, Series E | 5.6 |
| Convertible Debentures | 0.1 |
| Total | 11.0 |
Additional information, including the Fortis 2013 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
| Interim Consolidated Financial Statements |
| For the three and nine months ended September 30, 2014 and 2013 |
| (Unaudited) |
Prepared in accordance with accounting principles generally accepted in the United States
| Fortis Inc. | ||||
| Consolidated Balance Sheets (Unaudited) | ||||
| As at | ||||
| (in millions of Canadian dollars) | ||||
| September 30, | December 31, | |||
| 2014 | 2013 | |||
| ASSETS | ||||
| Current assets | ||||
| Cash and cash equivalents | $ | 458 | $ | 72 |
| Installment receivable (Note 6) | 1,201 | - | ||
| Accounts receivable and other current assets | 782 | 732 | ||
| Prepaid expenses | 75 | 45 | ||
| Inventories | 347 | 143 | ||
| Regulatory assets (Note 4) | 225 | 150 | ||
| Assets held for sale (Note 14) | - | 112 | ||
| Deferred income taxes | 155 | 42 | ||
| 3,243 | 1,296 | |||
| Other assets | 411 | 246 | ||
| Regulatory assets (Note 4) | 2,019 | 1,672 | ||
| Deferred income taxes | 28 | 7 | ||
| Utility capital assets | 16,267 | 11,618 | ||
| Non-utility capital assets | 662 | 649 | ||
| Intangible assets | 458 | 345 | ||
| Goodwill | 3,652 | 2,075 | ||
| $ | 26,740 | $ | 17,908 | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | ||||
| Current liabilities | ||||
| Short-term borrowings (Note 21) | $ | 1,564 | $ | 160 |
| Accounts payable and other current liabilities | 1,284 | 957 | ||
| Regulatory liabilities (Note 4) | 209 | 140 | ||
| Current installments of long-term debt | 887 | 780 | ||
| Current installments of capital lease and finance obligations (Note 5) | 222 | 7 | ||
| Liabilities associated with assets held for sale (Note 14) | - | 32 | ||
| Deferred income taxes | 9 | 8 | ||
| 4,175 | 2,084 | |||
| Other liabilities | 886 | 627 | ||
| Regulatory liabilities (Note 4) | 1,331 | 902 | ||
| Deferred income taxes | 1,773 | 1,078 | ||
| Convertible debentures represented by installment receipts (Note 6) | 1,800 | - | ||
| Long-term debt | 9,086 | 6,424 | ||
| Capital lease and finance obligations (Note 5) | 498 | 417 | ||
| 19,549 | 11,532 | |||
| Shareholders' equity | ||||
| Common shares (1)(Note 7) | 3,873 | 3,783 | ||
| Preference shares (Note 8) | 1,820 | 1,229 | ||
| Additional paid-in capital | 17 | 17 | ||
| Accumulated other comprehensive income (loss) | 34 | (72) | ||
| Retained earnings | 1,042 | 1,044 | ||
| 6,786 | 6,001 | |||
| Non-controlling interests | 405 | 375 | ||
| 7,191 | 6,376 | |||
| $ | 26,740 | $ | 17,908 | |
| (1) | No par value. Unlimited authorized shares; 216.0 million and 213.2 million issued and outstanding as at September 30, 2014 and December 31, 2013, respectively |
| Commitments and Contingencies (Notes 22 and 24, respectively) |
| See accompanying Notes to Interim Consolidated Financial Statements |
| Fortis Inc. | |||||||||||||
| Consolidated Statements of Earnings (Unaudited) | |||||||||||||
| For the periods ended September 30 | |||||||||||||
| (in millions of Canadian dollars, except per share amounts) | |||||||||||||
| Quarter Ended | Nine Months Ended | ||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||
| Revenue | $ | 1,197 | $ | 915 | $ | 3,708 | $ | 2,818 | |||||
| Expenses | |||||||||||||
| Energy supply costs | 406 | 311 | 1,488 | 1,098 | |||||||||
| Operating | 384 | 286 | 1,010 | 713 | |||||||||
| Depreciation and amortization | 181 | 140 | 478 | 399 | |||||||||
| 971 | 737 | 2,976 | 2,210 | ||||||||||
| Operating income | 226 | 178 | 732 | 608 | |||||||||
| Other income (expenses), net (Note 11) | (43 | ) | 2 | (37 | ) | (36 | ) | ||||||
| Finance charges (Note 12) | 159 | 103 | 406 | 284 | |||||||||
| Earnings before income taxes, discontinued operations and extraordinary item | 24 | 77 | 289 | 288 | |||||||||
| Income tax (recovery) expense (Note 13) | (8 | ) | 8 | 40 | 4 | ||||||||
| Earnings from continuing operations | 32 | 69 | 249 | 284 | |||||||||
| (Loss) earnings from discontinued operations, net of tax (Note 14) | - | (2 | ) | 5 | (2 | ) | |||||||
| Earnings before extraordinary item | 32 | 67 | 254 | 282 | |||||||||
| Extraordinary gain, net of tax (Note 15) | - | - | - | 22 | |||||||||
| Net earnings | $ | 32 | $ | 67 | $ | 254 | $ | 304 | |||||
| Net earnings attributable to: | |||||||||||||
| Non-controlling interests | $ | 3 | $ | 3 | $ | 8 | $ | 7 | |||||
| Preference equity shareholders | 15 | 16 | 42 | 44 | |||||||||
| Common equity shareholders | 14 | 48 | 204 | 253 | |||||||||
| $ | 32 | $ | 67 | $ | 254 | $ | 304 | ||||||
| Earnings per common share from continuing operations (Note 16) | |||||||||||||
| Basic | $ | 0.06 | $ | 0.24 | $ | 0.93 | $ | 1.17 | |||||
| Diluted | $ | 0.06 | $ | 0.24 | $ | 0.93 | $ | 1.17 | |||||
| Earnings per common share (Note 16) | |||||||||||||
| Basic | $ | 0.06 | $ | 0.23 | $ | 0.95 | $ | 1.27 | |||||
| Diluted | $ | 0.06 | $ | 0.23 | $ | 0.95 | $ | 1.27 | |||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||||||
| Fortis Inc. | |||||||||||
| Consolidated Statements of Comprehensive Income (Unaudited) | |||||||||||
| For the periods ended September 30 | |||||||||||
| (in millions of Canadian dollars) | |||||||||||
| Quarter Ended | Nine Months Ended | ||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||
| Net earnings | $ | 32 | $ | 67 | $ | 254 | $ | 304 | |||
| Other comprehensive income (loss) | |||||||||||
| Unrealized foreign currency translation gains (losses), net of hedging activities and tax | 107 | (15 | ) | 109 | (7 | ) | |||||
| Unrealized employee future benefits gains, net of tax | - | - | 1 | 2 | |||||||
| 107 | (15 | ) | 110 | (5 | ) | ||||||
| Comprehensive income | $ | 139 | $ | 52 | $ | 364 | $ | 299 | |||
| Comprehensive income attributable to: | |||||||||||
| Non-controlling interests | $ | 3 | $ | 3 | $ | 8 | $ | 7 | |||
| Preference equity shareholders | 15 | 16 | 42 | 44 | |||||||
| Common equity shareholders | 121 | 33 | 314 | 248 | |||||||
| $ | 139 | $ | 52 | $ | 364 | $ | 299 | ||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||||
| Fortis Inc. | |||||||||||||
| Consolidated Statements of Cash Flows (Unaudited) | |||||||||||||
| For the periods ended September 30 | |||||||||||||
| (in millions of Canadian dollars) | |||||||||||||
| Quarter Ended | Nine Months Ended | ||||||||||||
| 2014 | 2013 | 2014 | 2013 | ||||||||||
| Operating activities | |||||||||||||
| Net earnings | $ | 32 | $ | 67 | $ | 254 | $ | 304 | |||||
| Adjustments to reconcile net earnings to net cash provided by operating activities: | |||||||||||||
| Depreciation - capital assets | 156 | 123 | 416 | 351 | |||||||||
| Amortization - intangible assets | 15 | 12 | 41 | 35 | |||||||||
| Amortization - other | 10 | 5 | 21 | 13 | |||||||||
| Deferred income tax expense (recovery) | 23 | 4 | 7 | (22 | ) | ||||||||
| Accrued employee future benefits | 9 | 12 | 8 | 14 | |||||||||
| Equity component of allowance for funds used during construction (Note 11) | (2 | ) | (1 | ) | (5 | ) | (5 | ) | |||||
| Other | 33 | 10 | 40 | (34 | ) | ||||||||
| Change in long-term regulatory assets and liabilities | (64 | ) | (41 | ) | (71 | ) | (43 | ) | |||||
| Change in non-cash operating working capital (Note 19) | (150 | ) | (85 | ) | (63 | ) | 53 | ||||||
| 62 | 106 | 648 | 666 | ||||||||||
| Investing activities | |||||||||||||
| Change in other assets and other liabilities | (1 | ) | (3 | ) | 3 | (9 | ) | ||||||
| Capital expenditures - utility capital assets | (316 | ) | (247 | ) | (815 | ) | (762 | ) | |||||
| Capital expenditures - non-utility capital assets | (11 | ) | (11 | ) | (27 | ) | (35 | ) | |||||
| Capital expenditures - intangible assets | (13 | ) | (8 | ) | (33 | ) | (24 | ) | |||||
| Contributions in aid of construction | 17 | 16 | 43 | 46 | |||||||||
| Proceeds on disposal and settlement of assets (Notes 14 and 15) | - | - | 107 | 19 | |||||||||
| Business acquisitions, net of cash acquired (Note 17) | (2,648 | ) | - | (2,648 | ) | (1,055 | ) | ||||||
| (2,972 | ) | (253 | ) | (3,370 | ) | (1,820 | ) | ||||||
| Financing activities | |||||||||||||
| Change in short-term borrowings | 1,463 | 23 | 1,402 | (55 | ) | ||||||||
| Proceeds from convertible debentures represented by installment receipts, net of issue costs (Note 6) | - | - | 561 | - | |||||||||
| Proceeds from long-term debt, net of issue costs | 586 | 150 | 846 | 201 | |||||||||
| Repayments of long-term debt and capital lease and finance obligations | (157 | ) | (5 | ) | (201 | ) | (70 | ) | |||||
| Net borrowings (repayments) under committed credit facilities | 326 | (187 | ) | 53 | 511 | ||||||||
| Advances from non-controlling interests | 5 | 1 | 22 | 44 | |||||||||
| Issue of common shares, net of costs and dividends reinvested (Note 7) | 5 | 3 | 28 | 592 | |||||||||
| Issue of preference shares, net of costs (Note 8) | 587 | 242 | 587 | 242 | |||||||||
| Redemption of preference shares (Note 8) | - | (125 | ) | - | (125 | ) | |||||||
| Dividends | |||||||||||||
| Common shares, net of dividends reinvested | (51 | ) | (49 | ) | (146 | ) | (134 | ) | |||||
| Preference shares | (15 | ) | (16 | ) | (42 | ) | (44 | ) | |||||
| Subsidiary dividends paid to non-controlling interests | (1 | ) | (2 | ) | (6 | ) | (7 | ) | |||||
| 2,748 | 35 | 3,104 | 1,155 | ||||||||||
| Effect of exchange rate changes on cash and cash equivalents | 8 | - | 4 | - | |||||||||
| Change in cash and cash equivalents | (154 | ) | (112 | ) | 386 | 1 | |||||||
| Cash and cash equivalents, beginning of period | 612 | 267 | 72 | 154 | |||||||||
| Cash and cash equivalents, end of period | $ | 458 | $ | 155 | $ | 458 | $ | 155 | |||||
| Supplementary Information to Consolidated Statements of Cash Flows (Note 19) | |||||||||||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||||||
| Fortis Inc. |
| Consolidated Statements of Changes in Equity (Unaudited) |
| For the periods ended September 30 |
| (in millions of Canadian dollars) |
Common Shares | Preference Shares | Additional Paid-in Capital | Accumu- lated Other Compre- hensive (Loss) Income | Retained Earnings | Non- Controlling Interests | Total Equity | ||||||||||||||
| (Note 7) | (Note 8) | |||||||||||||||||||
| As at January 1, 2014 | $ | 3,783 | $ | 1,229 | $ | 17 | $ | (72 | ) | $ | 1,044 | $ | 375 | $ | 6,376 | |||||
| Net earnings | - | - | - | - | 246 | 8 | 254 | |||||||||||||
| Other comprehensive income | - | - | - | 110 | - | - | 110 | |||||||||||||
| Preference share issue | - | 591 | - | - | - | - | 591 | |||||||||||||
| Common share issues | 90 | - | (2 | ) | - | - | - | 88 | ||||||||||||
| Stock-based compensation | - | - | 2 | - | - | - | 2 | |||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 22 | 22 | |||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | 6 | 6 | |||||||||||||
| Unrealized losses on cash flow hedges assumed on acquisition (Notes 17 and 20) | - | - | - | (4 | ) | - | - | (4 | ) | |||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (6 | ) | (6 | ) | |||||||||||
| Dividends declared on common shares ($0.96 per share) | - | - | - | - | (206 | ) | - | (206 | ) | |||||||||||
| Dividends declared on preference shares | - | - | - | - | (42 | ) | - | (42 | ) | |||||||||||
| As at September 30, 2014 | $ | 3,873 | $ | 1,820 | $ | 17 | $ | 34 | $ | 1,042 | $ | 405 | $ | 7,191 | ||||||
| As at January 1, 2013 | $ | 3,121 | $ | 1,108 | $ | 15 | $ | (96 | ) | $ | 952 | $ | 310 | $ | 5,410 | |||||
| Net earnings | - | - | - | - | 297 | 7 | 304 | |||||||||||||
| Other comprehensive loss | - | - | - | (5 | ) | - | - | (5 | ) | |||||||||||
| Preference share issue | - | 244 | - | - | - | - | 244 | |||||||||||||
| Preference share redemption | - | (123 | ) | - | - | - | - | (123 | ) | |||||||||||
| Common share issues | 639 | - | (1 | ) | - | - | - | 638 | ||||||||||||
| Stock-based compensation | - | - | 2 | - | - | - | 2 | |||||||||||||
| Advances from non-controlling interests | - | - | - | - | - | 44 | 44 | |||||||||||||
| Foreign currency translation impacts | - | - | - | - | - | 1 | 1 | |||||||||||||
| Subsidiary dividends paid to non-controlling interests | - | - | - | - | - | (7 | ) | (7 | ) | |||||||||||
| Dividends declared on common shares ($0.93 per share) | - | - | - | - | (192 | ) | - | (192 | ) | |||||||||||
| Dividends declared on preference shares | - | - | - | - | (44 | ) | - | (44 | ) | |||||||||||
| As at September 30, 2013 | $ | 3,760 | $ | 1,229 | $ | 16 | $ | (101 | ) | $ | 1,013 | $ | 355 | $ | 6,272 | |||||
| See accompanying Notes to Interim Consolidated Financial Statements |
| FORTIS INC. |
| NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS |
| For the three and nine months ended September 30, 2014 and 2013 (unless otherwise stated) |
| (Unaudited) |
1. DESCRIPTION OF THE BUSINESS
NATURE OF OPERATIONS
Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas distribution 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 and non-utility assets, which are treated as two separate segments. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.
The following outlines each of the Corporation's reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation's 2013 annual audited consolidated financial statements, except as follows as a result of the acquisition of UNS Energy Corporation ("UNS Energy") (Note 17). UNS Energy is reported as part of the segment "Regulated Electric & Gas Utilities - United States" and the former "Other Canadian Electric Utilities" segment is now "Eastern Canadian Electric Utilities" and now includes Newfoundland Power, Maritime Electric and FortisOntario.
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities are as follows:
- Regulated Electric & Gas Utilities - United States: Includes 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 17) and Central Hudson Gas & Electric Corporation ("Central Hudson") acquired by Fortis in June 2013.
- Regulated Gas Utilities - Canadian: Includes the FortisBC Energy companies, primarily comprised of FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. and FortisBC Energy (Whistler) Inc.
- Regulated Electric Utilities - Canadian: Comprised of FortisAlberta, FortisBC Electric, and Eastern Canadian Electric Utilities (Newfoundland Power, Maritime Electric and FortisOntario). FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and Power Company, Limited and Algoma Power Inc.
- Regulated Electric Utilities - Caribbean: Comprised of Caribbean Utilities, in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos").
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation assets in Belize, Ontario, British Columbia and Upstate New York.
NON-REGULATED - NON-UTILITY
- Fortis Properties: Fortis Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in eight Canadian provinces, and owns and operates approximately 2.8 million square feet of commercial office and retail space, primarily in Atlantic Canada. In September 2014 the Corporation announced that it will engage in a review of strategic options for its hotel and commercial real estate business. Strategic options may include, but are not limited to, a sale of all or a portion of the assets, a sale of shares of Fortis Properties or an initial public offering. This review process commenced in October 2014 and is expected to continue through the balance of 2014 and into 2015.
- Griffith: Griffith Energy Services, Inc. ("Griffith") was acquired by Fortis in June 2013 as part of the acquisition of Central Hudson and was sold in March 2014 (Note 14).
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.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2013 annual audited consolidated financial statements. In management's opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the consolidated financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of electricity and gas demand and water flows, as well as the timing and recognition of regulatory decisions. As a result of natural gas consumption patterns, most of the annual earnings of the FortisBC Energy companies 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. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary.
The preparation of the consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three and nine months ended September 30, 2014. However, the magnitude of the accounting estimates has increased due to the acquisition of UNS Energy.
An evaluation of subsequent events through to November 6, 2014, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at September 30, 2014.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests, including the financial statements of UNS Energy commencing August 15, 2014, the date of acquisition (Note 17). All significant intercompany balances and transactions have been eliminated on consolidation.
These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2013 annual audited consolidated financial statements, except as described below.
Effective January 1, 2014, as approved in its Multi-Year Performance-Based Ratemaking Plan, FEI began depreciating utility capital assets and amortizing intangible assets the year after the assets are available for use. Prior to January 1, 2014, depreciation and amortization commenced the month after the assets were available for use.
As required by its regulator, UNS Energy classifies certain inventories held for the development, construction and betterment of utility capital assets as inventories in current assets. The Corporation's other regulated utilities classify these inventories as part of utility capital assets.
UNS Energy has interests in jointly-owned generating and transmission systems and accounts for its share of the utility capital assets and operating expenses related to these facilities using proportionate consolidation.
Regulation
The UNS Utilities are regulated by the Arizona Corporation Commission ("ACC") regarding such matters as retail electric and gas rates, construction, operations, financing, accounting, transactions with affiliated parties and issuance of securities. Certain activities of the utilities are subject to regulation by U.S. Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States), including such matters as the terms and prices of transmission services and wholesale electricity sales.
The UNS Utilities operate under cost of service ("COS") regulation as administered by the ACC. The ACC provides for the use of a historical test year in the establishment of retail electric and gas rates for the utilities and, pursuant to this method, the determination of the approved rate of return on original cost rate base and capital structure and all reasonable and prudently incurred costs establishes the revenue requirement upon which the Company's customer rates are determined. Retail electric and gas rates are set to provide the utilities with an opportunity to recover their costs of service 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. Once rates are approved, they are not adjusted as a result of actual COS being different from that which was estimated, other than for certain prescribed costs that are eligible for deferral account treatment.
Rates charged to retail customers include flow-through mechanisms that allow the utilities to recover the prudently incurred actual costs of its fuel, transmission, and energy purchases, and the prudent cost of contracts for hedging fuel and purchased power costs. The difference between costs recovered through rates and actual fuel, transmission and energy costs prudently incurred to provide retail electric and gas service is subject to deferral account treatment.
TEP and UNS Electric are required to comply with the ACC's Renewable Energy Standard ("RES"), which requires the utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements in 2025. The utilities must file annual RES implementation plans for review and approval by the ACC. The approved cost of carrying out those plans 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.
TEP, UNS Electric and UNS Gas are required to implement cost-effective Demand-Side Management ("DSM") programs to comply with the ACC's Energy Efficiency ("EE") Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs of implementing DSM programs. 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.
TEP's allowed ROE is set at 10.0% on a capital structure of 43.5% common equity, effective from July 1, 2013. The existing rate order at TEP also provides for an Environmental Compliance Adjustor mechanism that allows for recovery of the costs of complying with environmental standards required by federal or other government agencies between rate cases. 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.
New Accounting Policies
Obligations Resulting from Joint and Several Liability Arrangements
Effective January 1, 2014, the Corporation adopted Accounting Standards Update ("ASU") No. 2013-04 Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The above-noted ASU was applied retrospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
Parent's Accounting for the Cumulative Translation Adjustment
Effective January 1, 2014, the Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 830, Foreign Currency Matters - Parent's Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity, as outlined in ASU No. 2013-05. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
Presentation of an Unrecognized Tax Benefit
Effective January 1, 2014, the Corporation adopted the amendments to ASC Topic 740, Income Taxes - Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, as outlined in ASU No. 2013-11. The amendments were applied by the Corporation prospectively and did not materially impact the Corporation's interim consolidated financial statements for the three and nine months ended September 30, 2014.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
In April 2014 the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in this update change the requirements for reporting discontinued operations and require additional disclosures about discontinued operations. This update is effective for annual and interim periods beginning on or after December 15, 2014 and is to be applied prospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
Revenue from Contracts with Customers
In May 2014 FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. 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 is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. Early adoption is not permitted. Fortis is assessing the impact that the adoption of this standard will have on its consolidated financial statements.
Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period
In June 2014 FASB issued ASU No. 2014-12, 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 amendments in this update are intended to resolve 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. This update is effective for annual and interim periods beginning on or after December 15, 2015 and may be applied prospectively or retrospectively. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern
In August 2014 FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The amendments in this update are intended to provide guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning on or after December 15, 2016. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements.
4. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation's regulatory assets and liabilities, refer to Note 7 to the Corporation's 2013 annual audited consolidated financial statements.
| As at | ||||
| September 30, | December 31, | |||
| ($ millions) | 2014 | 2013 | ||
| Regulatory assets | ||||
| Deferred income taxes (i) | 931 | 833 | ||
| Employee future benefits (i) | 475 | 440 | ||
| Rate stabilization accounts (i) | 141 | 85 | ||
| Manufactured gas plant ("MGP") site remediation deferral (ii) | 121 | 47 | ||
| Deferred lease costs (i) | 103 | 76 | ||
| Deferred energy management costs (i) | 100 | 76 | ||
| Deferred operating overhead costs | 51 | 43 | ||
| Deferred net losses on disposal of utility capital assets and intangible assets | 37 | 35 | ||
| Final mine reclamation and retiree health care costs (i) | 32 | - | ||
| Natural gas for transportation incentives | 25 | 8 | ||
| Income taxes recoverable on other post-employment benefit ("OPEB") plans | 24 | 24 | ||
| Property tax deferral (i) | 23 | - | ||
| Customer Care Enhancement Project cost deferral | 19 | 21 | ||
| Other regulatory assets (i) (iii) | 162 | 134 | ||
| Total regulatory assets | 2,244 | 1,822 | ||
| Less: current portion | (225 | ) | (150 | ) |
| Long-term regulatory assets | 2,019 | 1,672 | ||
| As at | ||||
| September 30, | December 31, | |||
| ($ millions) | 2014 | 2013 | ||
| Regulatory liabilities | ||||
| Non-asset retirement obligation removal cost provision (iv) | 925 | 563 | ||
| Rate stabilization accounts (iv) | 165 | 177 | ||
| Deferred income taxes (iv) | 90 | 45 | ||
| Alberta Electric System Operator charges deferral | 68 | 73 | ||
| Employee future benefits | 61 | 55 | ||
| Customer and community benefits obligation (iv) | 59 | 23 | ||
| Carrying charges - employee future benefits | 22 | 16 | ||
| Renewable energy surcharge (iv) | 39 | - | ||
| Other regulatory liabilities (iii) (iv) | 111 | 90 | ||
| Total regulatory liabilities | 1,540 | 1,042 | ||
| Less: current portion | (209 | ) | (140 | ) |
| Long-term regulatory liabilities | 1,331 | 902 | ||
Description of the Nature of Regulatory Assets and Liabilities
- The respective regulatory assets as at September 30, 2014 include amounts related to UNS Energy. 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 is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP is permitted to fully recover these costs from customers when the costs are invoiced by the miners and expects to recover these costs over the remaining life of the mines, which is estimated to be between 14-20 years. Property tax deferrals at UNS Energy are being amortized and collected from customers over a six-month period, as approved by the regulator.
- In May 2014 remediation investigation was completed at one of Central Hudson's seven MGP sites, resulting in the recognition of an approximate $65 million (US$58 million) remediation liability. As authorized by the regulator, 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, which resulted in a corresponding increase in the MGP site remediation deferral (Note 24).
- Other regulatory assets and liabilities relate to all of the Corporation's regulated utilities. The balance is comprised of various items, each individually less than $20 million.
- The respective regulatory liabilities as at September 30, 2014 include amounts related to UNS Energy. The renewable energy surcharge liability represents amounts collected from customers associated with meeting the ACC's RES. TEP and UNS Electric are required to expand the use of renewable energy in order to meet standards set by the regulator and are permitted to recover these costs through a customer surcharge until these costs are incorporated into base customer rates.
As approved by the ACC, Fortis committed to provide UNS Energy's customers with financial benefits that would not have been realized in the absence of the acquisition. These incremental benefits include US$10 million in year one and US$5 million annually in years two through five to cover credits in retail customer rates. As a result, approximately $33 million (US$30 million) in expenses were recognized in the third quarter of 2014 (Notes 11 and 17).
5. CAPITAL LEASE AND FINANCE OBLIGATIONS
As a result of the acquisition of UNS Energy, the Corporation assumed US$260 million of capital lease obligations related to the Springerville generating facilities.
Springerville Unit 1 Leases have an initial term to January 2015, and include a fair market value purchase option. In 2013 UNS Energy elected to purchase leased interests for US$65 million, representing an additional 35.4% ownership interest. Upon close of the lease options, UNS Energy will own 49.5% of Springerville Unit 1. UNS Energy has also recognized an investment in lease equity of US$36 million relating to Springerville Unit 1 that is recorded in other long-term assets. These investments do not reduce the capital lease obligations reflected on the consolidated balance sheet as there is no legal right of offset.
Springerville Coal Handling Facilities Leases have an initial term to April 2015 and include a fixed-price purchase provision of US$120 million. In April 2014 UNS Energy elected to purchase an ownership interest upon the expiration of the lease term. UNS Energy has agreements with third parties to either purchase a portion of the UNS Energy's ownership in Springerville Coal Handling Facilities or to continue to use the facilities with payments to UNS Energy.
Springerville Common Facilities Leases 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. Instead of extending the leases, UNS Energy may exercise a fixed-price purchase provision of US$38 million in 2017 and US$68 million in 2021.
6. CONVERTIBLE DEBENTURES REPRESENTED BY INSTALLMENT RECEIPTS
To finance a portion of the acquisition of UNS Energy, in January 2014, Fortis, through a direct wholly owned subsidiary, completed the sale of $1.8 billion aggregate principal amount of 4% convertible unsecured subordinated debentures, represented by Installment Receipts (the "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 Toronto Stock Exchange ("TSX") under the symbol "FTS.IR" from January 9, 2014 to October 27, 2014. The Convertible Debentures are not listed. The Convertible Debentures will mature on January 9, 2024 and accrued interest at an annual rate of 4% per $1,000 principal amount of Convertible Debentures from January 9, 2014 to and including the Final Installment Date, after which the interest rate is 0%.
Since the Final Installment Date occurred prior to the first anniversary of the closing of the offering, holders of Convertible Debentures who paid the final installment in October 2014 received, in addition to the payment of accrued and unpaid interest, a make-whole payment, representing the interest that would have accrued from the day following the Final Installment Date to and including January 9, 2015. Approximately $33 million ($23 million after tax) and $67 million ($47 million after tax) in interest expense associated with the Convertible Debentures, including the make-whole payment, was recognized in the third quarter and year-to-date 2014, respectively (Note 12). An additional $5 million ($4 million after tax) in interest expense will be recognized in the fourth quarter of 2014 representing interest on the Convertible Debentures from October 1, 2014 to and including the Final Installment Date, for a total of approximately $72 million ($51 million after tax) recognized in 2014.
At the option of the holders, each fully paid Convertible Debenture is 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 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. After the Final Installment Date, any Convertible Debentures not converted may be redeemed by Fortis at a price equal to their principal amount. At maturity, Fortis will have the right to pay the principal amount due in common shares, which will be valued at 95% of the weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity date.
The proceeds of the first installment payment of the Convertible Debentures received on January 9, 2014 were approximately $599 million, or $561 million net of issue costs, which were used to partially finance the acquisition of UNS Energy and for general corporate purposes. The proceeds of the final installment payment received on October 28, 2014 were approximately $1.2 billion, or $1.165 billion net of issue costs. The net proceeds of the final installment were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy (Note 17).
7. COMMON SHARES
Common shares issued during the period were as follows:
| Quarter Ended | Year-to -Date | ||||
| September 30, 2014 | September 30, 2014 | ||||
| Number of | Number of | ||||
| Shares | Amount | Shares | Amount | ||
| (in thousands) | ($ millions) | (in thousands) | ($ millions) | ||
| Balance, beginning of period | 215,335 | 3,849 | 213,165 | 3,783 | |
| Dividend Reinvestment Plan | 568 | 19 | 1,959 | 62 | |
| Consumer Share Purchase Plan | 8 | 1 | 27 | 1 | |
| Employee Share Purchase Plan | 69 | 2 | 312 | 9 | |
| Stock Option Plans | 50 | 2 | 567 | 18 | |
| Balance, end of period | 216,030 | 3,873 | 216,030 | 3,873 | |
8. PREFERENCE SHARES
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.
The First Preference Shares, Series M are entitled to receive fixed cumulative preferential cash dividends as and when declared by the Board of Directors of the Corporation at a rate of 4.1%, in an amount equal to $1.0250 per share per annum, for each year up to but excluding December 1, 2019. The dividends are payable in equal quarterly installments on the first day of each quarter. For each five-year period after that date, the holders of First Preference Shares, Series M are entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 2.48%.
On each Series M Conversion Date, the holders of First Preference Shares, Series M, have the option to convert any or all of their First Preference Shares, Series M into an equal number of Cumulative Redeemable Floating Rate First Preference Shares, Series N ("First Preference Shares, Series N"). The holders of the Corporation's First Preference Shares, 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 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 2.48%.
On each Series N Conversion Date, the holders of First Preference Shares, Series N, have the option to convert any or all of their First Preference Shares, Series N into an equal number of Cumulative Redeemable Floating Rate First Preference Shares, Series M.
On or after specified dates, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series M and First Preference Shares, Series N at specified fixed prices per share plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption.
First Preference Shares, Series M and First Preference Shares, Series N do not have fixed maturity dates and are not redeemable at the option of the holders.
In July 2013 the Corporation redeemed all of the issued and outstanding $125 million 5.45% First Preference Shares, Series C at a redemption price of $25.1456 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share. Upon redemption, approximately $2 million of after-tax issuance costs associated with First Preference Shares, Series C were recognized in net earnings attributable to preference equity shareholders.
In July 2013 the Corporation issued 10 million Cumulative Redeemable Fixed Rate Reset First Preference Shares, Series K at a price of $25.00 per share for net after-tax proceeds of $244 million.
9. STOCK-BASED COMPENSATION PLANS
Stock Options
In 2014 the Corporation granted options to purchase common shares under the 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant. The options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan.
The following options were granted in 2014. The fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions.
| August 2014 | June 2014 | February 2014 | ||
| Options granted (#) | 12,216 | 23,584 | 925,172 | |
| Exercise price ($) | 33.44 | 32.23 | 30.73 | |
| Grant date fair value ($) | 2.47 | 2.69 | 3.53 | |
| Assumptions: | ||||
| Dividend yield (%) | 3.8 | 3.8 | 3.8 | |
| Expected volatility (%) | 15.7 | 15.9 | 20.3 | |
| Risk-free interest rate (%) | 1.45 | 1.52 | 1.69 | |
| Weighted average expected life (years) | 5.5 | 5.5 | 5.5 | |
Directors' Deferred Share Unit Plan
In January 2014, 7,766 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the first quarter equity component of the Directors' annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.
In April 2014, 7,520 DSUs were granted to the Corporation's Board of Directors, representing the second quarter equity component of the Directors' annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash.
In July 2014, 7,203 DSUs were granted to the Corporation's Board of Directors, representing the third quarter equity component of the Directors' annual compensation and, where opted, their third quarter component of annual retainers in lieu of cash.
Performance Share Unit Plans
The Corporation's Performance Share Unit ("PSU") Plans represent a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made, as determined by the Human Resources Committee of the Board of Directors. Each PSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.
In January, June and August 2014, 155,133, 23,791 and 4,277 PSUs, respectively, were granted to senior management of the Corporation and its subsidiaries under the 2013 PSU Plan. In April 2014, 78,536 share units were granted to senior management of a U.S. subsidiary of the Corporation under a 2014 Share Unit Plan. The 2014 Share Unit Plan was modelled after the Corporation's 2013 PSU Plan, with differences in the payment criteria at the end of the three-year vesting period.
In March 2014, 33,559 PSUs, representing two-thirds of the vested PSUs, were paid out to the Chief Executive Officer ("CEO") of the Corporation at $30.67 per PSU, for a total of approximately $1 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2011 and the CEO satisfying two of the three payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.
For the three and nine months ended September 30, 2014, stock-based compensation expense of approximately $4 million and $9 million, respectively, was recognized ($1 million and $5 million for the three and nine months ended September 30, 2013, respectively).
10. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group registered retirement savings plans, for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.
| Quarter Ended September 30 | ||||||||
| Defined Benefit | ||||||||
| Pension Plans | OPEB Plans | |||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | ||||
| Components of net benefit cost: | ||||||||
| Service costs | 12 | 10 | 3 | 3 | ||||
| Interest costs | 23 | 18 | 5 | 4 | ||||
| Expected return on plan assets | (28 | ) | (21 | ) | (2 | ) | - | |
| Amortization of actuarial losses | 8 | 13 | 1 | 3 | ||||
| Amortization of past service costs (credits)/plan amendments | 1 | - | (2 | ) | (2 | ) | ||
| Regulatory adjustments | 2 | (3 | ) | 2 | (2 | ) | ||
| Net benefit cost | 18 | 17 | 7 | 6 | ||||
| Year-to-Date September 30 | ||||||||
| Defined Benefit | ||||||||
| Pension Plans | OPEB Plans | |||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | ||||
| Components of net benefit cost: | ||||||||
| Service costs | 31 | 26 | 8 | 7 | ||||
| Interest costs | 64 | 41 | 15 | 10 | ||||
| Expected return on plan assets | (76 | ) | (48 | ) | (6 | ) | - | |
| Amortization of actuarial losses | 23 | 27 | 3 | 6 | ||||
| Amortization of past service costs (credits)/plan amendments | 1 | - | (7 | ) | (4 | ) | ||
| Regulatory adjustments | 7 | (10 | ) | 5 | (1 | ) | ||
| Net benefit cost | 50 | 36 | 18 | 18 | ||||
For the three and nine months ended September 30, 2014, the Corporation expensed $5 million and $15 million, respectively ($5 million and $12 million for the three and nine months ended September 30, 2013, respectively), related to defined contribution pension plans.
11. OTHER INCOME (EXPENSES), NET
| Quarter Ended | Year-to-Date | |||||||
| September 30 | September 30 | |||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | ||||
| Equity component of allowance for funds used during construction ("AFUDC") | 2 | 1 | 5 | 5 | ||||
| Net foreign exchange gain (loss) | 5 | (2 | ) | 5 | 3 | |||
| Interest income | 3 | 3 | 10 | 5 | ||||
| Acquisition-related expenses (Note 17) | (20 | ) | (1 | ) | (24 | ) | (9 | ) |
| Acquisition-related customer and community benefits (Notes 4 and 17) | (33 | ) | - | (33 | ) | (41 | ) | |
| Other | - | 1 | - | 1 | ||||
| (43 | ) | 2 | (37 | ) | (36 | ) | ||
The net foreign exchange gain and loss relates to the translation into Canadian dollars of the Corporation's US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity (Notes 21 and 23).
The acquisition-related expenses and customer and community benefits in 2014 were associated with the acquisition of UNS Energy (Notes 1 and 17) and in 2013 were associated with the acquisition of Central Hudson.
12. FINANCE CHARGES
| Quarter Ended | Year-to-Date | ||||||||
| September 30 | September 30 | ||||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | |||||
| Interest: | |||||||||
| Long-term debt and capital lease and finance obligations | 124 | 106 | 344 | 294 | |||||
| Convertible debentures represented by installment receipts (Note 6) | 33 | - | 67 | - | |||||
| Short-term borrowings | 8 | 2 | 13 | 6 | |||||
| Debt component of AFUDC | (6 | ) | (5 | ) | (18 | ) | (16 | ) | |
| 159 | 103 | 406 | 284 | ||||||
13. INCOME TAXES
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 income taxes to consolidated effective income taxes.
| Quarter Ended | Year-to-Date | |||||||
| September 30 | September 30 | |||||||
| ($ millions, except as noted) | 2014 | 2013 | 2014 | 2013 | ||||
| Combined Canadian federal and provincial statutory income tax rate | 29.0 | % | 29.0 | % | 29.0 | % | 29.0 | % |
| Statutory income tax rate applied to earnings before income taxes | 7 | 22 | 84 | 84 | ||||
| Difference between Canadian statutory income tax rate and rates applicable to foreign subsidiaries | (2 | ) | (6 | ) | (7 | ) | (13 | ) |
| Difference in Canadian provincial statutory income tax rates applicable to subsidiaries in different Canadian jurisdictions | - | - | (7 | ) | (8 | ) | ||
| Items capitalized for accounting purposes but expensed for income tax purposes | (9 | ) | (14 | ) | (31 | ) | (41 | ) |
| Difference between capital cost allowance and amounts claimed for accounting purposes | - | 9 | - | 7 | ||||
| Impacts associated with Part VI.1 tax | - | - | - | (23 | ) | |||
| Release of income tax reserves | - | (2 | ) | - | (7 | ) | ||
| Other | (4 | ) | (1 | ) | 1 | 5 | ||
| Income tax (recovery) expense | (8 | ) | 8 | 40 | 4 | |||
| Effective income tax rate | (33.3 | )% | 10.4 | % | 13.8 | % | 1.4 | % |
In June 2013 the Government of Canada enacted changes associated with Part VI.1 tax on the Corporation's preference share dividends. In accordance with US GAAP, income taxes are required to be recognized based on enacted tax legislation. In 2013 the Corporation recognized an approximate $23 million income tax recovery due to the enactment of higher deductions associated with Part VI.1 tax.
In June 2013 a settlement was reached with Canada Revenue Agency resulting in the release of income tax provisions of approximately $5 million.
14. SALE OF GRIFFITH
In March 2014 Griffith was sold for proceeds of approximately $105 million (US$95 million). The assets and liabilities of Griffith were classified as held for sale on the consolidated balance sheet as at December 31, 2013 and the results of operations to the date of sale are presented as discontinued operations on the consolidated statements of earnings for the three and nine months ended September 30, 2014.
The table below details the results of discontinued operations.
| Quarter Ended | Year-to-Date | ||||||
| September 30 | September 30 | ||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | |||
| Revenue | - | 56 | 95 | 56 | |||
| (Loss) earnings from discontinued operations before income taxes | - | (3 | ) | 8 | (3 | ) | |
| Income tax recovery (expense) | - | 1 | (3 | ) | 1 | ||
| (Loss) earnings from discontinued operations, net of tax | - | (2 | ) | 5 | (2 | ) | |
15. EXTRAORDINARY GAIN, NET OF TAX
In March 2013 the Corporation and the Government of Newfoundland and Labrador settled all matters, including release from all debt obligations, pertaining to the Government's December 2008 expropriation of non-regulated hydroelectric generating assets and water rights in central Newfoundland, then owned by the Exploits River Hydro Partnership, in which Fortis held an indirect 51% interest. As a result of the settlement, an extraordinary gain of approximately $25 million ($22 million after tax) was recognized in the first quarter of 2013.
16. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS was as follows:
| Quarter Ended September 30, 2014 | |||||||||||||
| Weighted | |||||||||||||
| Net Earnings to Common Shareholders | Average | EPS | |||||||||||
| Continuing | Discontinued | Extraordinary | Number of | ||||||||||
| Operations | Operations | Item | Total | Shares | Continuing | Discontinued | Extraordinary | ||||||
| ($ millions) | ($ millions) | ($ millions) | ($ millions) | (millions) | Operations | Operations | Item | Total | |||||
| Basic EPS | 14 | - | - | 14 | 215.6 | $0.06 | $- | $- | $0.06 | ||||
| Effect of potential dilutive securities: | |||||||||||||
| Stock Options | - | - | - | - | 0.5 | ||||||||
| Preference Shares | 2 | - | - | 2 | 6.9 | ||||||||
| 16 | - | - | 16 | 223.0 | |||||||||
| Deduct anti-dilutive impacts: | |||||||||||||
| Preference Shares | (2 | ) | - | - | (2 | ) | (6.9 | ) | |||||
| Diluted EPS | 14 | - | - | 14 | 216.1 | $0.06 | $- | $- | $0.06 | ||||
| Quarter Ended September 30, 2013 | |||||||||||||||
| Weighted | |||||||||||||||
| Net Earnings to Common Shareholders | Average | EPS | |||||||||||||
| Continuing | Discontinued | Extraordinary | Number of | ||||||||||||
| Operations | Operations | Item | Total | Shares | Continuing | Discontinued | Extraordinary | ||||||||
| ($ millions) | ($ millions) | ($ millions) | ($ millions) | (millions) | Operations | Operations | Item | Total | |||||||
| Basic EPS | 50 | (2 | ) | - | 48 | 212.0 | $0.24 | $(0.01 | ) | $- | $0.23 | ||||
| Effect of potential dilutive securities: | |||||||||||||||
| Stock Options | - | - | - | - | 0.7 | ||||||||||
| Preference Shares | 3 | - | - | 3 | 6.5 | ||||||||||
| 53 | (2 | ) | - | 51 | 219.2 | ||||||||||
| Deduct anti-dilutive impacts: | |||||||||||||||
| Preference Shares | (3 | ) | - | - | (3 | ) | (6.5 | ) | |||||||
| Diluted EPS | 50 | (2 | ) | - | 48 | 212.7 | $0.24 | $(0.01 | ) | $- | $0.23 | ||||
| Year-to-Date September 30, 2014 | |||||||||||||
| Weighted | |||||||||||||
| Net Earnings to Common Shareholders | Average | EPS | |||||||||||
| Continuing | Discontinued | Extraordinary | Number of | ||||||||||
| Operations | Operations | Item | Total | Shares | Continuing | Discontinued | Extraordinary | ||||||
| ($ millions) | ($ millions) | ($ millions) | ($ millions) | (millions) | Operations | Operations | Item | Total | |||||
| Basic EPS | 199 | 5 | - | 204 | 214.6 | $0.93 | $0.02 | $- | $0.95 | ||||
| Effect of potential dilutive securities: | |||||||||||||
| Stock Options | - | - | - | - | 0.5 | ||||||||
| Preference Shares | 7 | - | - | 7 | 6.9 | ||||||||
| 206 | 5 | - | 211 | 222.0 | |||||||||
| Deduct anti-dilutive impacts: | |||||||||||||
| Preference Shares | (7 | ) | - | - | (7 | ) | (6.9 | ) | |||||
| Diluted EPS | 199 | 5 | - | 204 | 215.1 | $0.93 | $0.02 | $- | $0.95 | ||||
| Year-to-Date September 30, 2013 | |||||||||||||||
| Weighted | |||||||||||||||
| Net Earnings to Common Shareholders | Average | EPS | |||||||||||||
| Continuing | Discontinued | Extraordinary | Number of | ||||||||||||
| Operations | Operations | Item | Total | Shares | Continuing | Discontinued | Extraordinary | ||||||||
| ($ millions) | ($ millions) | ($ millions) | ($ millions) | (millions) | Operations | Operations | Item | Total | |||||||
| Basic EPS | 233 | (2 | ) | 22 | 253 | 199.1 | $1.17 | $(0.01 | ) | $0.11 | $1.27 | ||||
| Effect of potential | |||||||||||||||
| dilutive securities: | |||||||||||||||
| Stock Options | - | - | - | - | 0.7 | ||||||||||
| Preference Shares | 11 | - | - | 11 | 8.8 | ||||||||||
| 244 | (2 | ) | 22 | 264 | 208.6 | ||||||||||
| Deduct anti-dilutive | |||||||||||||||
| impacts: | |||||||||||||||
| Preference Shares | (11 | ) | - | - | (11 | ) | (8.8 | ) | |||||||
| Diluted EPS | 233 | (2 | ) | 22 | 253 | 199.8 | $1.17 | $(0.01 | ) | $0.11 | $1.27 | ||||
17. BUSINESS ACQUISITION
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. The net cash purchase price of approximately $2.7 billion (US$2.5 billion) was initially financed through: (i) drawings of $2 billion under the Corporation's acquisition credit facilities, consisting of a $1.7 billion short-term bridge facility, repayable in full nine months following its advance, and a $300 million medium-term bridge facility, repayable in full on the second anniversary of its advance (together, the "Acquisition Credit Facilities"); (ii) available cash on hand; and (iii) drawings of US$265 million under the Corporation's revolving credit facility.
UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through its primary subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 658,000 electricity and gas customers. UNS Energy has three regulated utility subsidiaries: TEP, UNS Electric and UNS Gas. TEP is a vertically integrated regulated electric utility and UNS Energy's largest operating subsidiary, representing approximately 85% of UNS Energy's total assets at September 30, 2014. The Company generates, transmits and distributes electricity to approximately 415,000 retail electric customers in southeastern Arizona. TEP's service territory covers 2,991 square kilometres and includes a population of approximately 1,000,000 people in the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. The Company has sufficient generating capacity which, together with existing power purchase agreements and expected generation plant additions, should satisfy the requirements of its customer base and meet expected future peak demand requirements. TEP also sells wholesale electricity to other entities in the western United States.
UNS Electric is a vertically integrated regulated electric utility, representing approximately 9% of UNS Energy's total assets at September 30, 2014. The Company generates, transmits and distributes electricity to approximately 93,000 retail electric customers in Arizona's Mohave and Santa Cruz counties, which have a combined population of approximately 250,000.
UNS Gas is a regulated gas distribution company, representing approximately 6% of UNS Energy's total assets at September 30, 2014. The company serves approximately 150,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties, which have a combined population of approximately 700,000.
TEP and UNS Electric currently own or lease generation resources with an aggregate capacity of 2,392 MW, including 18 MW of solar capacity. Several of the generating assets in which UNS Energy has an interest are jointly owned. As at September 30, 2014, approximately 70% of UNS Energy's generating capacity is fuelled by coal. UNS Energy has a long-term energy resource diversification strategy to provide long-term rate stability for customers, mitigate environmental impacts, comply with regulatory requirements and leverage existing utility infrastructure. TEP is reducing its reliance on coal over the next few years by replacing portions of existing coal generation with efficient combined-cycle gas turbines and renewables, particularly by adding solar generating capacity, and expects coal to represent less than 50% of generating capacity by the year 2020.
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. Therefore, in determining the fair value of assets and liabilities of UNS Energy at the date of acquisition, fair value approximates book value. 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 preliminary 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=CDN$1.0925.
| ($ 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) (1) | (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 | 1,510 |
| (1) | As at September 30, 2014, UNS Energy held US$245 million and US$1.4 billion in variable-rate and fixed-rate debt, respectively. Interest rates on the variable-rate debt are based on either LIBOR or weekly tax-exempt market rates with US$30 million maturing in 2015 and the remaining terms to maturity ranging from 2 years to 18 years. Fixed-rate debt has interest rates ranging from 3.85% to 7.10% with US$130 million maturing in 2015 and the remaining terms to maturity ranging from 6 years to 30 years. |
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. Financial results of the Corporation include revenue of $249 million (US $227 million) and earnings of $37 million (US$34 million) from UNS Energy for the three and nine months ended September 30, 2014.
Acquisition-related expenses totalled approximately $20 million ($15 million after tax) and $24 million ($18 million after tax) for the three and nine ended September 30, 2014, respectively, and have been recognized in other income (expenses), net on the consolidated statement of earnings (Note 11). In addition, approximately $33 million (US$30 million), or $20 million (US$18 million) after tax, in customer benefits offered to obtain regulatory approval of the acquisition were expensed in the third quarter of 2014 and were also recognized in other income (expenses), net on the consolidated statement of earnings (Notes 4 and 11).
Supplemental Pro Forma Data
The unaudited pro forma financial information below gives effect to the acquisition of UNS Energy as if the transaction had occurred at the beginning of 2013. This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2013, nor is it necessarily indicative of the results that may be expected in future periods.
| Quarter Ended | Year-to-Date | |||
| September 30 | September 30 | |||
| ($ millions) | 2014 | 2013 | 2014 | 2013 |
| Pro forma revenue | 1,446 | 1,369 | 4,747 | 3,979 |
| Pro forma net earnings (1) | 142 | 139 | 457 | 422 |
| (1) | Pro forma net earnings exclude all acquisition-related expenses incurred by UNS Energy and the Corporation, net of tax (Note 11). A pro forma adjustment has been made to net earnings for the respective periods presented to reflect the Corporation's after-tax financing costs associated with the acquisition. |
18. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| REGULATED | NON-REGULATED | |||||||||||||||||||
| United States | Canada | |||||||||||||||||||
| Quarter Ended | Electric & Gas | Gas | Electric | |||||||||||||||||
| September 30, 2014 ($ millions) | UNS Ener- gy | Cen- tral Hud- son | Total | Fortis- BC Ener- gy | Fortis Alber- ta | Fortis- BC Elec- tric | Eas- tern Cana- dian | Total | Carib- bean Elec- tric | Fortis Gene- ration | Non- Utility | Corpo- rate and Other | Inter- seg- ment elimina- tions | Total | ||||||
| Revenue | 249 | 173 | 422 | 208 | 131 | 78 | 198 | 615 | 85 | 8 | 68 | 9 | (10 | ) | 1,197 | |||||
| Energy supply costs | 95 | 61 | 156 | 68 | - | 18 | 115 | 201 | 50 | - | - | - | (1 | ) | 406 | |||||
| Operating expenses | 61 | 79 | 140 | 72 | 43 | 22 | 33 | 170 | 13 | 3 | 44 | 16 | (2 | ) | 384 | |||||
| Depreciation and amortization | 26 | 12 | 38 | 50 | 40 | 16 | 20 | 126 | 9 | 1 | 6 | 1 | - | 181 | ||||||
| Operating income | 67 | 21 | 88 | 18 | 48 | 22 | 30 | 118 | 13 | 4 | 18 | (8 | ) | (7 | ) | 226 | ||||
| Other income (expenses), net | 1 | 2 | 3 | - | (1 | ) | 1 | 1 | 1 | 1 | - | - | (48 | ) | - | (43 | ) | |||
| Finance charges | 11 | 9 | 20 | 35 | 21 | 11 | 13 | 80 | 3 | - | 6 | 57 | (7 | ) | 159 | |||||
| Income tax expense (recovery) | 20 | 6 | 26 | (4 | ) | (1 | ) | 3 | 5 | 3 | - | - | 3 | (40 | ) | - | (8 | ) | ||
| Net earnings (loss) | 37 | 8 | 45 | (13 | ) | 27 | 9 | 13 | 36 | 11 | 4 | 9 | (73 | ) | - | 32 | ||||
| Non-controlling interests | - | - | - | - | - | - | - | - | 3 | - | - | - | - | 3 | ||||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 15 | - | 15 | ||||||
| Net earnings (loss) attributable to common equity shareholders | 37 | 8 | 45 | (13 | ) | 27 | 9 | 13 | 36 | 8 | 4 | 9 | (88 | ) | - | 14 | ||||
| Goodwill | 1,547 | 505 | 2,052 | 913 | 227 | 235 | 67 | 1,442 | 158 | - | - | - | - | 3,652 | ||||||
| Identifiable assets | 5,171 | 1,979 | 7,150 | 4,668 | 3,435 | 1,779 | 2,094 | 11,976 | 754 | 932 | 700 | 2,152 | (576 | ) | 23,088 | |||||
| Total assets | 6,718 | 2,484 | 9,202 | 5,581 | 3,662 | 2,014 | 2,161 | 13,418 | 912 | 932 | 700 | 2,152 | (576 | ) | 26,740 | |||||
| Gross capital expenditures | 45 | 35 | 80 | 75 | 83 | 20 | 42 | 220 | 14 | 15 | 11 | - | - | 340 | ||||||
| Quarter Ended | ||||||||||||||||||||
| September 30, 2013 | ||||||||||||||||||||
| ($ millions) | ||||||||||||||||||||
| Revenue | - | 170 | 170 | 194 | 119 | 74 | 202 | 589 | 77 | 12 | 68 | 6 | (7 | ) | 915 | |||||
| Energy supply costs | - | 62 | 62 | 64 | - | 19 | 119 | 202 | 47 | - | - | - | - | 311 | ||||||
| Operating expenses | - | 72 | 72 | 69 | 39 | 19 | 31 | 158 | 10 | 2 | 43 | 2 | (1 | ) | 286 | |||||
| Depreciation and amortization | - | 10 | 10 | 44 | 37 | 12 | 20 | 113 | 9 | 2 | 6 | - | - | 140 | ||||||
| Operating income | - | 26 | 26 | 17 | 43 | 24 | 32 | 116 | 11 | 8 | 19 | 4 | (6 | ) | 178 | |||||
| Other income (expenses), net | - | 1 | 1 | 1 | - | - | 1 | 2 | 1 | - | - | (1 | ) | (1 | ) | 2 | ||||
| Finance charges | - | 8 | 8 | 35 | 18 | 10 | 14 | 77 | 4 | - | 8 | 13 | (7 | ) | 103 | |||||
| Income tax expense (recovery) | - | 7 | 7 | (5 | ) | - | 3 | 5 | 3 | - | - | 3 | (5 | ) | - | 8 | ||||
| Net earnings (loss) from continuing operations | - | 12 | 12 | (12 | ) | 25 | 11 | 14 | 38 | 8 | 8 | 8 | (5 | ) | - | 69 | ||||
| Loss from discontinued operations, net of tax | - | - | - | - | - | - | - | - | - | - | (2 | ) | - | - | (2 | ) | ||||
| Net earnings (loss) | - | 12 | 12 | (12 | ) | 25 | 11 | 14 | 38 | 8 | 8 | 6 | (5 | ) | - | 67 | ||||
| Non-controlling interests | - | - | - | 1 | - | - | - | 1 | 2 | - | - | - | - | 3 | ||||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 16 | - | 16 | ||||||
| Net earnings (loss) attributable to common equity shareholders | - | 12 | 12 | (13 | ) | 25 | 11 | 14 | 37 | 6 | 8 | 6 | (21 | ) | - | 48 | ||||
| Goodwill | - | 476 | 476 | 913 | 227 | 235 | 67 | 1,442 | 146 | - | - | - | - | 2,064 | ||||||
| Identifiable assets | - | 1,710 | 1,710 | 4,504 | 2,973 | 1,775 | 2,073 | 11,325 | 673 | 837 | 792 | 637 | (468 | ) | 15,506 | |||||
| Total assets | - | 2,186 | 2,186 | 5,417 | 3,200 | 2,010 | 2,140 | 12,767 | 819 | 837 | 792 | 637 | (468 | ) | 17,570 | |||||
| Gross capital expenditures | - | 28 | 28 | 54 | 77 | 25 | 37 | 193 | 11 | 22 | 12 | - | - | 266 | ||||||
| REGULATED | NON-REGULATED | ||||||||||||||||||||
| United States | Canada | ||||||||||||||||||||
| Year-to-Date | Electric & Gas | Gas | Electric | ||||||||||||||||||
| September 30, 2014 ($ millions) | UNS Ener- gy | Cen- tral Hud- son | Total | Fortis- BC Ener- gy | Fortis Alber- ta | Fortis- BC Elec- tric | Eas- tern Cana- dian | Total | Carib- bean Elec- tric | Fortis Gene- ration | Non- Utility | Corpo- rate and Other | Inter- segment elimina- tions | Total | |||||||
| Revenue | 249 | 635 | 884 | 1,003 | 386 | 244 | 742 | 2,375 | 237 | 30 | 187 | 24 | (29 | ) | 3,708 | ||||||
| Energy supply costs | 95 | 277 | 372 | 438 | - | 62 | 476 | 976 | 141 | 1 | - | - | (2 | ) | 1,488 | ||||||
| Operating expenses | 61 | 248 | 309 | 210 | 128 | 65 | 106 | 509 | 32 | 7 | 129 | 30 | (6 | ) | 1,010 | ||||||
| Depreciation and amortization | 26 | 35 | 61 | 142 | 122 | 44 | 59 | 367 | 27 | 4 | 17 | 2 | - | 478 | |||||||
| Operating income | 67 | 75 | 142 | 213 | 136 | 73 | 101 | 523 | 37 | 18 | 41 | (8 | ) | (21 | ) | 732 | |||||
| Other income (expenses), net | 1 | 5 | 6 | 2 | 1 | 1 | 2 | 6 | 2 | (1 | ) | - | (49 | ) | (1 | ) | (37 | ) | |||
| Finance charges | 11 | 26 | 37 | 105 | 60 | 30 | 42 | 237 | 11 | - | 18 | 125 | (22 | ) | 406 | ||||||
| Income tax expense (recovery) | 20 | 21 | 41 | 31 | (1 | ) | 10 | 15 | 55 | - | 1 | 7 | (64 | ) | - | 40 | |||||
| Net earnings (loss) from continuing operations | 37 | 33 | 70 | 79 | 78 | 34 | 46 | 237 | 28 | 16 | 16 | (118 | ) | - | 249 | ||||||
| Earnings from discontinued | |||||||||||||||||||||
| operations, net of tax | - | - | - | - | - | - | - | - | - | - | 5 | - | - | 5 | |||||||
| Net earnings (loss) | 37 | 33 | 70 | 79 | 78 | 34 | 46 | 237 | 28 | 16 | 21 | (118 | ) | - | 254 | ||||||
| Non-controlling interests | - | - | - | 1 | - | - | - | 1 | 7 | - | - | - | - | 8 | |||||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 42 | - | 42 | |||||||
| Net earnings (loss) attributable to common equity shareholders | 37 | 33 | 70 | 78 | 78 | 34 | 46 | 236 | 21 | 16 | 21 | (160 | ) | - | 204 | ||||||
| Goodwill | 1,547 | 505 | 2,052 | 913 | 227 | 235 | 67 | 1,442 | 158 | - | - | - | - | 3,652 | |||||||
| Identifiable assets | 5,171 | 1,979 | 7,150 | 4,668 | 3,435 | 1,779 | 2,094 | 11,976 | 754 | 932 | 700 | 2,152 | (576 | ) | 23,088 | ||||||
| Total assets | 6,718 | 2,484 | 9,202 | 5,581 | 3,662 | 2,014 | 2,161 | 13,418 | 912 | 932 | 700 | 2,152 | (576 | ) | 26,740 | ||||||
| Gross capital expenditures | 45 | 84 | 129 | 200 | 244 | 58 | 105 | 607 | 42 | 70 | 27 | - | - | 875 | |||||||
| Year-to-Date | |||||||||||||||||||||
| September 30, 2013 | |||||||||||||||||||||
| ($ millions) | |||||||||||||||||||||
| Revenue | - | 170 | 170 | 932 | 354 | 230 | 714 | 2,230 | 213 | 24 | 186 | 19 | (24 | ) | 2,818 | ||||||
| Energy supply costs | - | 62 | 62 | 386 | - | 58 | 462 | 906 | 131 | - | - | - | (1 | ) | 1,098 | ||||||
| Operating expenses | - | 72 | 72 | 206 | 117 | 61 | 95 | 479 | 26 | 7 | 126 | 8 | (5 | ) | 713 | ||||||
| Depreciation and amortization | - | 10 | 10 | 136 | 109 | 37 | 59 | 341 | 26 | 4 | 17 | 1 | - | 399 | |||||||
| Operating income | - | 26 | 26 | 204 | 128 | 74 | 98 | 504 | 30 | 13 | 43 | 10 | (18 | ) | 608 | ||||||
| Other income (expenses), net | - | 1 | 1 | 2 | 2 | 1 | 2 | 7 | 2 | - | - | (45 | ) | (1 | ) | (36 | ) | ||||
| Finance charges | - | 8 | 8 | 106 | 53 | 29 | 42 | 230 | 11 | - | 20 | 34 | (19 | ) | 284 | ||||||
| Income tax expense (recovery) | - | 7 | 7 | 21 | 1 | 9 | (2 | ) | 29 | - | - | 6 | (38 | ) | - | 4 | |||||
| Net earnings (loss) from continuing operations | - | 12 | 12 | 79 | 76 | 37 | 60 | 252 | 21 | 13 | 17 | (31 | ) | - | 284 | ||||||
| Loss from discontinued operations, net of tax | - | - | - | - | - | - | - | - | - | - | (2 | ) | - | - | (2 | ) | |||||
| Extraordinary gain, net of tax | - | - | - | - | - | - | - | - | - | 22 | - | - | - | 22 | |||||||
| Net earnings (loss) | - | 12 | 12 | 79 | 76 | 37 | 60 | 252 | 21 | 35 | 15 | (31 | ) | - | 304 | ||||||
| Non-controlling interests | - | - | - | 1 | - | - | - | 1 | 6 | - | - | - | - | 7 | |||||||
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | - | 44 | - | 44 | |||||||
| Net earnings (loss) attributable to common equity shareholders | - | 12 | 12 | 78 | 76 | 37 | 60 | 251 | 15 | 35 | 15 | (75 | ) | - | 253 | ||||||
| Goodwill | - | 476 | 476 | 913 | 227 | 235 | 67 | 1,442 | 146 | - | - | - | - | 2,064 | |||||||
| Identifiable assets | - | 1,710 | 1,710 | 4,504 | 2,973 | 1,775 | 2,073 | 11,325 | 673 | 837 | 792 | 637 | (468 | ) | 15,506 | ||||||
| Total assets | - | 2,186 | 2,186 | 5,417 | 3,200 | 2,010 | 2,140 | 12,767 | 819 | 837 | 792 | 637 | (468 | ) | 17,570 | ||||||
| Gross capital expenditures | - | 28 | 28 | 154 | 306 | 58 | 103 | 621 | 35 | 101 | 36 | - | - | 821 | |||||||
Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant related party inter-segment transactions for the three and nine months ended September 30, 2014 and 2013 were as follows:
| Significant Related Party Inter-Segment Transactions | Quarter Ended | Year-to-Date | |||
| September 30 | September 30 | ||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | |
| Sales from Fortis Generation to Eastern Canadian Electric Utilities | 1 | - | 2 | 1 | |
| Sales from Eastern Canadian Electric Utilities to Non-Utility | 1 | 1 | 4 | 4 | |
| Inter-segment finance charges on lending from: | |||||
| Corporate to Regulated Electric Utilities - Canadian | - | - | 1 | - | |
| Corporate to Regulated Electric Utilities - Caribbean | 1 | 1 | 4 | 3 | |
| Corporate to Non-Utility | 6 | 4 | 16 | 14 | |
| The significant related party inter-segment asset balances were as follows: | |||||
| As at | |||||
| September 30 | |||||
| ($ millions) | 2014 | 2013 | |||
| Inter-segment lending from: | |||||
| Fortis Generation to Eastern Canadian Electric Utilities | 20 | 20 | |||
| Corporate to Regulated Gas Utilities - Canadian | 18 | - | |||
| Corporate to Regulated Electric Utilities - Canadian | 25 | - | |||
| Corporate to Regulated Electric Utilities - Caribbean | 101 | 83 | |||
| Corporate to Fortis Generation | - | 13 | |||
| Corporate to Non-Utility | 396 | 325 | |||
| Other inter-segment assets | 16 | 27 | |||
| Total inter-segment eliminations | 576 | 468 | |||
19. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| Quarter Ended | Year-to-Date | |||||||
| September 30 | September 30 | |||||||
| ($ millions) | 2014 | 2013 | 2014 | 2013 | ||||
| Change in non-cash operating working capital: | ||||||||
| Accounts receivable and other current assets | 83 | 64 | 171 | 190 | ||||
| Prepaid expenses | (30 | ) | (20 | ) | (16 | ) | (18 | ) |
| Inventories | (67 | ) | (35 | ) | (51 | ) | (17 | ) |
| Regulatory assets - current portion | 18 | 29 | 17 | 69 | ||||
| Accounts payable and other current liabilities | (128 | ) | (112 | ) | (162 | ) | (185 | ) |
| Regulatory liabilities - current portion | (26 | ) | (11 | ) | (22 | ) | 14 | |
| (150 | ) | (85 | ) | (63 | ) | 53 | ||
| Non-cash investing and financing activities: | ||||||||
| Common share dividends reinvested | 18 | 17 | 60 | 51 | ||||
| Additions to utility and non-utility capital assets, and intangible assets included in current liabilities | 187 | 84 | 187 | 84 | ||||
| Contributions in aid of construction included in current assets | 10 | 13 | 10 | 13 | ||||
| Exercise of stock options into common shares | - | - | 2 | 1 | ||||
| Convertible debentures represented by installment receipts (Note 6) | 1,201 | - | 1,201 | - | ||||
20. 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 reoccurring 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 their derivative contracts under master netting agreements and collateral positions.
| As at September 30, 2014 | |||||
| ($ millions) | Level 1 | Level 2 | Level 3(2) | Total | |
| Assets | |||||
| Electricity swap contracts (1) | - | - | 23 | 23 | |
| Gas swaps and options contracts (1) | - | 1 | 3 | 4 | |
| Electricity power contracts (1) | - | 1 | 1 | 2 | |
| Other investments (3) | 7 | 28 | - | 35 | |
| Total gross assets | 7 | 30 | 27 | 64 | |
| Less: Counterparty netting not offset on the balance sheet (5) | - | - | - | (3 | ) |
| Total net assets | 7 | 30 | 27 | 61 | |
| Liabilities | |||||
| Electricity swap contracts (1) | - | - | 1 | 1 | |
| Gas swaps and options contracts (1) | 1 | 4 | 4 | 9 | |
| Gas purchase contract premiums (1) | - | 3 | - | 3 | |
| Electricity power contracts (1) | - | - | 4 | 4 | |
| Energy contracts - cash flow hedge (4) | - | - | 1 | 1 | |
| Interest rate swaps - cash flow hedge (4) | - | 5 | - | 5 | |
| Total gross liabilities | 1 | 12 | 10 | 23 | |
| Less: Counterparty netting not offset on the balance sheet (5) | - | - | - | (3 | ) |
| Total net liabilities | 1 | 12 | 10 | 20 | |
| As at December 31, 2013 | |||||
| ($ millions) | Level 1 | Level 2 | Level 3(2) | Total | |
| Assets | |||||
| Electricity swap contracts (1) | - | - | 10 | 10 | |
| Other investments (3) | 6 | - | - | 6 | |
| Total gross assets | 6 | - | 10 | 16 | |
| Less: Counterparty netting not offset on the balance sheet (5) | - | - | - | - | |
| Total net assets | 6 | - | 10 | 16 | |
| Liabilities | |||||
| Gas swaps and options contracts (1) | - | 13 | - | 13 | |
| Gas purchase contract premiums (1) | - | 2 | - | 2 | |
| Total gross liabilities | - | 15 | - | 15 | |
| Less: Counterparty netting not offset on the balance sheet (5) | - | - | - | - | |
| Total net liabilities | - | 15 | - | 15 | |
| (1) | The fair value of the Corporation's energy contracts are recorded in accounts receivable and other current assets, long-term other assets, accounts payable and other current liabilities and long-term other liabilities. Gains and losses arising from changes in fair value on these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in rates as permitted by the regulators. |
| (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. |
| (3) | Included in long-term other assets on the consolidated balance sheet. |
| (4) | 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 the other comprehensive income until they become realized and are reclassified to earnings. |
| (5) | 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. |
Derivative Instruments
Regulatory Deferral Contracts
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges. The Corporation is required to record all derivative instruments at fair value except for those that qualify for the normal purchase and normal sale exception. The fair values of the derivatives 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.
Central Hudson holds electricity swap contracts and gas swap and option contracts. The electricity swap contracts and natural gas derivatives are used by Central Hudson to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair values of the electricity swap contracts and natural gas derivatives were calculated using forward pricing provided by independent third parties.
The FortisBC Energy companies hold gas swap and option contracts and gas purchase contract premiums. The natural gas derivatives are used by the FortisBC Energy companies 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.
UNS Energy holds electricity power contracts, gas swap and option contracts and gas purchase swap contracts to reduce its exposure to energy price risk associated with gas and purchased power requirements. UNS Energy primarily applies the market approach for recurring 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 options are 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.
As at September 30, 2014, the energy contract derivatives were not designated as hedges; however, any gains or losses associated with changes in the fair value of the derivatives were 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. Unrealized losses of $17 million were recognized in current regulatory assets and unrealized gains of $29 million were recognized in current and long-term regulatory liabilities as at September 30, 2014 (December 31, 2013 - unrealized losses of $15 million and unrealized gains of $10 million, respectively).
Cash Flow Hedges
UNS Energy has entered into interest rate swaps, expiring through 2020, to mitigate its exposure to volatility in variable interest rates on debt, and a power purchase swap, expiring 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 hedging activities are reported in the statements of other comprehensive income and reclassified to earnings as they become realized. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $3 million.
Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.
Volume of Derivative Activity
As at September 30, 2014, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.
| 2014 | 2015 | 2016 | 2017 | |
| Electricity swap and option contracts (gigawatt hours) | 433 | 1,200 | 659 | 219 |
| Electricity power contracts (gigawatt hours) | 310 | 1,097 | - | - |
| Gas swap and option contracts (petajoules) | 14 | 48 | 7 | 2 |
| Gas purchase contract premiums (petajoules) | 33 | 66 | - | - |
| Energy contracts - cash flow hedges (petajoules) | - | 59 | - | - |
Financial Instruments Not Carried At Fair Value
The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
| As at | ||||||||
| Asset (Liability) | September 30, 2014 | December 31, 2013 | ||||||
| Carrying | Estimated | Carrying | Estimated | |||||
| ($ millions) | Value | Fair Value | Value | Fair Value | ||||
| Long-term other asset - Belize Electricity (1) | 113 | n/a (2) | 108 | n/a (2) | ||||
| Investment in lease equity (1) | 40 | 29 | - | - | ||||
| Long-term debt, including current portion (3) | (9,973 | ) | (11,427 | ) | (7,204 | ) | (8,084 | ) |
| Waneta Expansion Limited Partnership ("Waneta Partnership") promissory note (4) | (52 | ) | (54 | ) | (50 | ) | (50 | ) |
| (1) | Included in long-term other assets on the consolidated balance sheet. Investment in lease equity was valued using level 3 inputs. |
| (2) | The Corporation's expropriated investment in Belize Electricity is recognized at book value, including foreign exchange impacts. The actual amount of compensation that the Government of Belize may pay to Fortis is indeterminable at this time (Notes 21 and 23). |
| (3) | The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $524 million (December 31, 2013 - $313 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs. |
| (4) | Included in long-term other liabilities on the consolidated balance sheet. |
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 fair value of the investment in lease equity is determined based on an estimated price at which an investor would realize a target internal rate of return and assumes a residual value based on an appraisal of Springerville generating station Unit 1 conducted in 2011. No impairment has been recorded as TEP expects to recover the full carrying value of the investment in retail rates.
21. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
| Credit risk | Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument. |
| Liquidity risk | Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments. |
| Market risk | Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk. |
Credit Risk
For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at September 30, 2014, FortisAlberta's gross credit risk exposure was approximately $112 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $2 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
The FortisBC Energy companies, UNS Energy and Central Hudson 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.
The Corporation is exposed to credit risk associated with the amount and timing of fair value compensation that Fortis is entitled to receive from the Government of Belize ("GOB") as a result of the expropriation of the Corporation's investment in Belize Electricity by the GOB on June 20, 2011. As at September 30, 2014, the Corporation had a long-term other asset of $113 million (December 31, 2013 - $108 million), including foreign exchange impacts, recognized on the consolidated balance sheet related to its expropriated investment in Belize Electricity (Notes 20 and 23).
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 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 larger regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.
The Corporation's $1 billion committed corporate credit facility is available for interim financing of acquisitions and for general corporate purposes. 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. As at September 30, 2014 over the next five years, average annual consolidated long-term debt maturities and repayments are expected to be approximately $340 million, excluding long-term credit facility borrowings. The combination of available credit facilities and relatively low annual debt maturities and repayments beyond 2014 provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at September 30, 2014, the Corporation and its subsidiaries had consolidated credit facilities of approximately $4.9 billion, of which $2.6 billion was unused, including $999 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, with no one bank holding more than 25% of these facilities. Approximately $4.6 billion of the total credit facilities are committed facilities with maturities ranging from 2015 through 2019.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| As at | ||||||||||
($ millions) | Regulated Utilities | Non-Regulated | Corporate and Other | September 30, 2014 | December 31, 2013 | |||||
| Total credit facilities | 1,986 | 13 | 2,900 | 4,899 | 2,695 | |||||
| Credit facilities utilized: | ||||||||||
| Short-term borrowings (1) | (246 | ) | - | (1,318 | ) | (1,564 | ) | (160 | ) | |
| Long-term debt (2) | (224 | ) | - | (300 | ) | (524 | ) | (313 | ) | |
| Letters of credit outstanding | (175 | ) | - | (1 | ) | (176 | ) | (66 | ) | |
| Credit facilities unused | 1,341 | 13 | 1,281 | 2,635 | 2,156 | |||||
| (1) | The weighted average interest rate on short-term borrowings was approximately 2.3% as at September 30, 2014 (December 31, 2013 - 1.3%) |
| (2) | As at September 30, 2014, credit facility borrowings classified as long term included $98 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2013 - $43 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.1% as at September 30, 2014 (December 31, 2013 - 1.8%). |
As at September 30, 2014 and December 31, 2013, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.
The significant changes in available credit facilities from that disclosed in the Corporation's 2013 annual audited consolidated financial statements are as follows.
In April 2014 FortisBC Electric extended the maturity of its $150 million unsecured committed revolving credit facility, with $100 million now maturing in May 2017 and $50 million now maturing in April 2015.
In July 2014 FEI, FortisAlberta and Newfoundland Power amended their $500 million, $250 million and $100 million, respectively, committed revolving credit facilities, resulting in extensions to their maturity dates to August 2016, August 2019 and August 2019, respectively, from August 2015, August 2018 and August 2017, respectively.
As at September 30, 2014, UNS Energy had a US$300 million ($336 million) unsecured committed revolving credit facility and a US$82 million ($92 million) letter of credit facility, both maturing in November 2016.
As at September 30, 2014, Corporate and Other credit facilities consisted of the following: (i) the Corporation's $1 billion unsecured committed revolving credit facility, maturing in July 2018; (ii) the Corporation's Acquisition Credit Facilities, consisting of $1.118 billion remaining under the short-term bridge facility maturing in May 2015, and $300 million remaining under the medium-term bridge facility maturing in August 2016; (iii) a new $200 million uncommitted non-revolving unsecured demand term credit facility at the Corporation, repayable in full in November 2014; (iv) a US$100 million ($112 million) unsecured committed revolving credit facility at CH Energy Group, maturing in October 2015; (v) a US$125 million ($140 million) unsecured committed revolving credit facility at UNS Energy Corporation, maturing in November 2016; and (vi) a $30 million unsecured committed revolving credit facility at FHI maturing in April 2015.
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at September 30, 2014, the Corporation's credit ratings were as follows:
| Standard & Poor's ("S&P") | A- / Negative (long-term corporate and unsecured debt credit rating) |
| DBRS | A(low) / Under Review - Developing Implications (unsecured debt credit rating) |
The above-noted credit ratings reflect the Corporation's 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 low levels of debt at the holding company level. In December 2013, after the announcement by Fortis that it had entered into an agreement to acquire UNS Energy, DBRS placed the Corporation's credit rating under review with developing implications and S&P revised its outlook on the Corporation to negative from stable. In October 2014, following the conversion of substantially all of Convertible Debentures into common shares, S&P revised its outlook on the Corporation to stable (Notes 6 and 25).
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment 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, Belize Electric Company Limited and FortisUS Energy Corporation is the US dollar.
As at September 30, 2014, the Corporation's corporately issued US$1,375 million (December 31, 2013 - US$1,033 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at September 30, 2014, the Corporation had approximately US$2,767 million (December 31, 2013 - US$560 million) in foreign net investments remaining to be hedged. The Corporation's US dollar-denominated foreign net investments as at September 30, 2014 were significantly impacted by the UNS Energy acquisition, which was substantially financed through Acquisition Credit Facilities denominated in Canadian dollars. 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 in 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 in other comprehensive income.
As a result of the acquisition of UNS Energy, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, including UNS Energy, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative-to-Canadian dollar exchange rate would increase or decrease earnings per common share of Fortis by approximately 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.
Effective June 20, 2011, the Corporation's asset associated with its expropriated investment in Belize Electricity (Notes 20 and 23) does not qualify for hedge accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As a result, foreign exchange gains and losses on the translation of the long-term other asset associated with Belize Electricity are recognized in earnings. The Corporation recognized in earnings a foreign exchange gain of approximately $5 million for the three and nine months ended September 30, 2014 (foreign exchange loss of $2 million for the three months ended and a foreign exchange gain of $3 million for the nine months ended September 30, 2013) (Note 11).
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price risk associated with changes in the market price of natural gas, UNS Energy is exposed to commodity price risk associated with changes in market price of gas and purchased power, and Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and natural gas (Note 20). The risks have been reduced by entering 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.
The price risk-management strategy of the FortisBC Energy companies aims to improve the likelihood that natural gas prices remain competitive, mitigate gas price volatility on customer rates and reduce the risk of regional price discrepancies. As directed by the regulator, the FortisBC Energy companies have suspended their commodity hedging activities, with the exception of certain limited swaps as permitted by the regulator. The existing hedging contracts will continue in effect through to their maturities and the FortisBC Energy companies' ability to fully recover the cost of gas in customer rates remains unchanged. Any differences between the cost of natural gas purchased and the price of natural gas included in customer rates are recorded as regulatory deferrals and are recovered from, or refunded to, customers in future rates, subject to regulatory approval.
22. COMMITMENTS
The material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2013 annual audited consolidated financial statement are detailed as follows.
As a result of the acquisition of UNS Energy (Note 17), the amount of the Corporation's commitments associated with long-term debt, interest obligations on long-term debt and capital lease and finance obligations increased as at September 30, 2014.
As at September 30, 2014 power purchase obligations include Central Hudson's contract to purchase 200 megawatts of installed capacity from May 2014 through April 2017, totalling US$51 million. Central Hudson's power purchase obligations also include an agreement to purchase available installed capacity from the Danskammer generating facility from October 2014 through August 2018, totalling approximately US$77 million as at September 30, 2014.
In May 2014 the BCUC approved FortisBC Electric's new power purchase agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh per year of associated energy for a 20-year term, effective July 1, 2014.
UNS Energy is party to 20-year long-term renewable power purchase agreements totalling approximately US$723 million as at September 30, 2014, which require UNS Energy to purchase 100% of the output of certain renewable energy generating facilities that have achieved commercial operation. UNS Energy has entered into additional long-term renewable power purchase agreements 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.
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 totaling US$252 million, US$214 million and US$80 million, respectively, as at September 30, 2014.
UNS Energy is party to renewable energy credit purchase agreements, totalling approximately US$124 million as at September 30, 2014, 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.
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.
Defined benefit pension funding contributions are based on estimates provided under the latest completed actuarial valuations, which generally provide funding estimates for a period of three to five years from the date of the valuations. Contributions have increased from that disclosed in the Corporation's 2013 annual audited consolidated financial statements and reflect estimates from the actuarial valuations completed as at December 31, 2013, as well as the acquisition of UNS Energy.
23. EXPROPRIATED ASSETS
On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. Consequent to the deprivation of control over the operations of the utility, the Corporation discontinued the consolidation method of accounting for Belize Electricity, as of June 20, 2011, and classified the book value, including foreign exchange impacts, of the expropriated investment as a long-term other asset on the consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to challenging the constitutionality of the expropriation of the Corporation's investment in Belize Electricity. Fortis commissioned an independent valuation of its expropriated investment and submitted its claim for compensation to the GOB in November 2011. The book value of the long-term other asset is below fair value as at the date of expropriation as determined by independent valuators. The GOB also commissioned a valuation of Belize Electricity, which is significantly lower than both the fair value determined under the Corporation's valuation and the book value of the long-term other asset.
In July 2012 the Belize Supreme Court dismissed the Corporation's claim of October 2011. Also in July 2012, Fortis filed its appeal of the above-noted trial judgment in the Belize Court of Appeal. The appeal was heard in October 2012 and a decision was rendered by the Belize Court of Appeal in May 2014. The two Belizean judges found in favour of the GOB; however, the third judge delivered a strong dissenting opinion concluding that the expropriation was contrary to the Belize Constitution. An appeal of the decision to the Caribbean Court of Justice, the final court for appeals arising in Belize, was filed in June 2014 and Fortis filed its written submission for appeal in October 2014. A hearing is scheduled for December 2014.
Fortis believes it has a strong, well-positioned case supporting the unconstitutionality of the expropriation. There exists, however, a possibility that the outcome of the litigation may be unfavourable to the Corporation and the amount of compensation to be paid to Fortis could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. The book value was $113 million, including foreign exchange impacts, as at September 30, 2014 (December 31, 2013 - $108 million). If the expropriation is held to be unconstitutional, it is not determinable at this time as to the nature of the relief that would be awarded to Fortis; for example: (i) ordering return of the shares to Fortis and/or award of damages; or (ii) ordering compensation to be paid to Fortis for the unconstitutional expropriation of the shares and/or award of damages. Based on presently available information, the $113 million long-term other asset is not deemed impaired as at September 30, 2014. Fortis will continue to assess for impairment each reporting period based on evaluating the outcomes of court proceedings and/or compensation settlement negotiations. As well as continuing the constitutional challenge of the expropriation, Fortis is also pursuing alternative options for obtaining fair compensation, including compensation under the Belize/United Kingdom Bilateral Investment Treaty.
24. 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.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed settlement agreement with counsel to plaintiff shareholders pertaining to several complaints, which named Fortis and other defendants, which were filed in, or transferred to, the Supreme Court of the State of New York, County of New York, relating to the acquisition of CH Energy Group by Fortis. The complaints generally alleged that the directors of CH Energy Group breached their fiduciary duties in connection with the acquisition and that CH Energy Group, Fortis, FortisUS Inc. and Cascade Acquisition Sub Inc. aided and abetted that breach. The settlement agreement was subject to court approval. In June 2014 the Supreme Court of the State of New York, County of New York issued an Order and Final Judgment approving the settlement agreement thereby concluding the proceedings.
Following the announcement of the acquisition of UNS Energy on December 11, 2013, four complaints which named Fortis and other defendants were filed in the Superior Court of the State of Arizona ("Superior Court") in and for the County of Pima and one claim in the United States District Court in and for the District of Arizona, challenging the acquisition. The complaints generally allege that the directors of UNS Energy breached their fiduciary duties in connection with the acquisition and that UNS Energy, Fortis, FortisUS Inc., and Color Acquisition Sub Inc. aided and abetted that breach. In March 2014 two of the four complaints filed in the Superior Court were dismissed by the plaintiffs and counsel for the parties in the two actions remaining in the Superior Court executed a Memorandum of Understanding recording an agreement-in-principle on the structure of a settlement to be proposed to the Superior Court for approval following closing of the acquisition. In April 2014 the complaint filed in the United States District Court was dismissed by the plaintiff. The outcome of these lawsuits cannot be predicted with any certainty 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 British Columbia Supreme Court ("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.
FortisBC Energy Companies
FEI was the plaintiff in a B.C. Supreme Court action against the City of Surrey ("Surrey") in which FEI sought the court's determination on the manner in which costs related to the relocation of a natural gas transmission pipeline would be shared between the Company and Surrey. The relocation was required due to the development and expansion of Surrey's transportation infrastructure. FEI claimed that the parties had an agreement that dealt with the allocation of costs. Surrey advanced counterclaims, including an allegation that FEI breached the agreement and that Surrey suffered damages as a result. In December 2013 the court issued a decision ordering FEI and Surrey to share equally the cost of the pipeline relocation. The court also decided that Surrey was successful in its counterclaim that FEI breached the agreement. The amount of damages that may be awarded to Surrey at a subsequent hearing cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices Code and negligence relating to a forest fire near Vaseux Lake in 2003, prior to the acquisition of FortisBC Electric by Fortis, and has filed and served a writ and statement of claim against FortisBC Electric dated August 2, 2005. In September 2014 a settlement was reached on the matter and a full release and consent dismissal of the action is pending. As FortisBC Electric was insured against this claim, the settlement is not expected to impact the Corporation's consolidated net earnings.
The Government of British Columbia filed a claim in the B.C. 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 not been served, the Company has retained counsel and has notified its insurers. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
Central Hudson
Former MGP Facilities
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 September 30, 2014, an obligation of US$105 million was recognized in respect of MGP remediation and, based upon cost model analysis completed in 2012, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$152 million.
Central Hudson has notified its insurers and intends to seek reimbursement from insurers for remediation, where coverage exists. Further, as authorized by the New York State Public Service Commission, 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 (Note 4).
Asbestos Litigation
Prior to and after the acquisition of CH Energy Group, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,347 asbestos cases have been raised, 1,172 remained pending as at September 30, 2014. Of the cases no longer pending against Central Hudson, 2,020 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 155 cases. The Company is presently unable to assess the validity of the remaining 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.
UNS Energy
San Juan Generating Station
San Juan Coal Company ("SJCC") operates an underground coal mine in an area where certain gas producers have oil and gas leases with the Government of the United States, the State of New Mexico, and private parties. These gas producers allege that SJCC's underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan generating station, which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. The Company cannot reasonably estimate the impact of any future claims by these gas producers and, accordingly, no amount has been accrued in the consolidated financial statements.
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$44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The mine reclamation liability recorded as at September 30, 2014 was US$21 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 credit-adjusted risk-free interest rate to be used to discount future liabilities. 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 customers and, accordingly, these costs are deferred as a regulatory asset (Note 4).
25. SUBSEQUENT EVENT
On October 28, 2014, the Corporation received gross proceeds of approximately $1.2 billion, or $1.165 billion net of issue costs, from the final installment payment of the Convertible Debentures (Note 6). The net proceeds of the final installment were used to repay a portion of borrowings under the Acquisition Credit Facilities used to initially finance the acquisition of UNS Energy (Note 17). 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.
26. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation.
CORPORATE INFORMATION
Fortis Inc. is a leader in the North American electric and gas utility business, with total assets of more than $25 billion and fiscal 2013 revenue exceeding $4 billion. Its regulated utilities account for approximately 90% of total assets and serve more than 3 million customers across Canada and in the United States and the Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada, Belize and Upstate New York. The Corporation's non-utility investment is comprised of hotels and commercial real estate in Canada.
The Common Shares; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the Toronto Stock Exchange and trade under the ticker symbols FTS, FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.J, FTS.PR.K, and FTS.PR.M, respectively.
| Transfer Agent and Registrar: |
| Computershare Trust Company of Canada |
| 9th Floor, 100 University Avenue |
| Toronto, ON M5J 2Y1 |
| 514.982.7555 or 1.866.586.7638 |
| 416.263.9394 or 1.888.453.0330 |
| www.investorcentre.com/fortisinc |
Additional information, including the Fortis 2013 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
Contact Information:
Executive Vice President, Chief Financial Officer
Fortis Inc.
709.737.2822