ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net earnings attributable to common equity shareholders of $143 million, or $0.67 per common share, compared to $151 million, or $0.79 per common share, for the first quarter of 2013.
Earnings for the first quarter of 2014 included $5 million, or $0.02 per common share, associated with Griffith Energy Services, Inc. ("Griffith"), which was sold in March 2014 for proceeds of approximately $105 million (US$95 million). Griffith was acquired as part of CH Energy Group, Inc. ("CH Energy Group") in June 2013. Earnings for the first quarter of 2014 were reduced by $11 million, or $0.05 per common share, in after-tax interest expense associated with convertible debentures issued to finance a portion of the pending acquisition of UNS Energy Corporation ("UNS Energy").
Earnings for the first quarter of 2013 included an after-tax extraordinary gain of $22 million, or $0.12 per common share, related to the settlement of expropriation matters associated with the Exploits River Hydro Partnership ("Exploits Partnership").
Excluding the impacts of Griffith, interest expense on the convertible debentures, and the Exploits Partnership, net earnings attributable to common equity shareholders for the first quarter of 2014 were $149 million, or $0.70 per common share, compared to $129 million, or $0.67 per common, for the same period last year.
Fortis announced in December 2013 that it agreed to acquire UNS Energy for US$60.25 per common share in cash, representing an aggregate purchase price of approximately US$4.3 billion, including the assumption of approximately US$1.8 billion of debt on closing. UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through three subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 657,000 electricity and gas customers. In March 2014 UNS Energy common shareholders approved the acquisition of UNS Energy by Fortis and in April 2014 the U.S. Federal Energy Regulatory Commission approved the transaction. The closing of the acquisition, which is expected to occur by the end of 2014, is subject to certain government and regulatory approvals, including approval by the Arizona Corporation Commission ("ACC"), compliance with other applicable U.S. legislative requirements and the satisfaction of customary closing conditions.
"The approval process for the UNS Energy acquisition is progressing well," says Stan Marshall, President and Chief Executive Officer, Fortis Inc. In April 2014 the ACC Staff and other Intervenors filed their direct testimony in the merger proceeding, indicating that they would support the merger subject to certain conditions. Settlement discussions are currently underway between the Corporation, UNS Energy, the ACC Staff and other Intervenors.
"The acquisition is consistent with the Corporation's strategy of investing in high-quality regulated utility assets in Canada and the United States and is expected to be accretive to earnings per common share of Fortis in the first full year after closing, excluding one-time acquisition-related costs," explains Marshall.
To finance a portion of the UNS Energy acquisition, 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. In March 2014 the Corporation secured, as bridge financing for the pending acquisition of UNS Energy, an aggregate of $2 billion non-revolving term credit facilities from a syndicate of banks.
The Corporation's regulated utilities contributed earnings of $162 million, up $17 million quarter over quarter. The increase was driven by earnings of $18 million at Central Hudson Gas & Electric Corporation ("Central Hudson"), which was acquired as part of CH Energy Group in June 2013. After considering the common share offering and financing costs associated with the acquisition, Central Hudson was slightly accretive to earnings per common share. Newfoundland Power's earnings were $3 million higher quarter over quarter, mainly related to regulator-approved adjustments, which impacted the timing of quarterly earnings. Earnings at Caribbean Regulated Electric Utilities were $2 million higher compared to the first quarter of 2013, driven by electricity sales growth. The increases were partially offset by lower earnings at the FortisBC Energy companies. The first stage of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia reduced the allowed rate of return on common shareholders' equity ("ROE") and equity component of capital structure for the benchmark utility, FortisBC Energy Inc., 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. As a result, a reduction of earnings of approximately $5 million at the FortisBC Energy companies and $1 million at FortisBC Electric related to the first quarter of 2013 was not recognized until the second quarter of 2013.
In February 2014 the FortisBC Energy companies received regulatory approval for the amalgamation of their 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 must receive the consent of the Lieutenant Governor in Council and is expected to be effective on or about December 31, 2014. In March 2014 the regulatory decision on the second stage of the GCOC Proceeding in British Columbia was received. The decision resulted in increases in the equity component of capital structures for FortisBC Energy (Vancouver Island) Inc. and FortisBC Energy (Whistler) Inc. ("FEWI"), as well as an increase in the allowed ROE for FEWI. The outcome of the second stage of the GCOC Proceeding did not have a material impact on earnings for the first quarter of 2014.
Multi-year performance-based rate applications are progressing in British Columbia and a cost of capital proceeding is continuing in Alberta. FortisAlberta is preparing to file a combined capital tracker application for 2013 through 2015, which is an application for revenue increases related to its capital program. Central Hudson will file a general rate application in the second half of 2014 to establish rates effective mid-2015.
Excluding the impact of the Exploits Partnership, Non-Regulated Fortis Generation contributed $6 million to earnings, up $4 million quarter over quarter. Improved performance was driven by increased production in Belize due to higher rainfall.
Excluding the impact of Griffith, Non-Utility operations contributed earnings of less than $0.5 million, comparable with the first quarter of 2013.
Excluding the interest expense on the convertible debentures, Corporate and Other expenses were $1 million higher quarter over quarter. The increase was primarily due to interest expense on debt issued to complete the financing of the acquisition of Central Hudson, partially offset by a higher income tax recovery.
In March 2014 Fortis priced a private placement of US$500 million senior unsecured notes. The notes will be 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%. Subject to the satisfaction of customary closing conditions, US$213 million of notes will be issued on June 30, 2014 and US$287 million of notes will be issued on September 15, 2014. Net proceeds from the sale of the notes will be used to refinance existing indebtedness and for general corporate purposes, including repayment of US-dollar drawings on the Corporation's committed credit facility.
Cash flow from operating activities was $265 million for the quarter compared to $283 million for the first quarter of 2013. Unfavourable changes in working capital were partially offset by favourable changes in long-term regulatory deferral accounts.
Fortis paid a dividend of 32 cents per common share on March 1, 2014, up from 31 cents for the fourth quarter of 2013. The 3.2% increase in the quarterly dividend translates into an annualized dividend of $1.28 and extends the Corporation's record of annual common share dividend increases to 41 consecutive years, the longest record of any public corporation in Canada.
Consolidated capital expenditures were approximately $237 million for the first quarter of 2014. Construction of the $900 million, 335-megawatt 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 $603 million has been invested in the Waneta Expansion since construction began in late 2010. FortisBC has begun preliminary work related to an expansion of its Tilbury liquefied natural gas ("LNG") facility in British Columbia. The Tilbury expansion, which remains subject to certain approvals, is estimated to cost approximately $400 million and is expected to include a second LNG tank and a new liquefier, both to be in service in 2016.
The Corporation's capital program is expected to total $1.4 billion in 2014. Over the five-year period 2014 through 2018, the Corporation's capital program is expected to exceed $6.5 billion. Additionally, UNS Energy has forecast that its capital program for 2015 through 2018 will be approximately $1.5 billion (US$1.4 billion).
"The Corporation expects earnings per common share growth in 2015 and beyond as a result of contributions from the Central Hudson and UNS Energy acquisitions, and our capital program, including the completion of the Waneta Expansion in 2015 and the Tilbury LNG facility expansion in 2016. This growth will support continuing growth in dividends," says Marshall.
"We are committed to grow your business profitably, while ever cognizant of our commitment to provide customers with safe, reliable, cost-effective energy service," he concludes.
| Interim Management Discussion and Analysis |
| For the three months ended March 31, 2014 |
| Dated May 8, 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 months ended March 31, 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 expected timing of closing the acquisition of UNS Energy Corporation ("UNS Energy") by Fortis and the expectation that the acquisition will be accretive to earnings per common share of Fortis in the first full year after closing, excluding one-time acquisition-related costs; the expected increase in the Corporation's rate base at the time of closing the acquisition of UNS Energy; the Corporation's forecast gross consolidated capital expenditures for 2014 and total capital spending over the five-year period 2014 through 2018; UNS Energy's forecast capital program for 2015 through 2018; the financing costs the Corporation expects to incur in 2014 associated with the convertible debentures represented by installment receipts (the "Debentures"); the expected net proceeds from the final installment of the Debentures; 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; the expected consolidated long-term debt maturities and repayments in 2014 and on average annually over the next five years; 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; and the expected timing of filing of regulatory applications and of receipt of regulatory decisions.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; FortisAlberta's continued recovery of its cost of service and ability to earn its allowed rate of return on common shareholder's equity ("ROE") under performance-based rate-setting ("PBR"), which commenced for a five-year term effective January 1, 2013; the receipt of certain regulatory and government approvals required to close the acquisition of UNS Energy; the receipt of the final installment of the Debentures; 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 gas and electricity 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 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; 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; risks relating to the ability to close the acquisition of UNS Energy, the timing of such closing and the realization of the anticipated benefits of the acquisition; 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 the largest investor-owned electric and gas distribution utility in Canada. Its regulated utilities account for approximately 90% of total assets and serve approximately 2.5 million customers across Canada and in New York State 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 March 31, 2014, the Corporation's electricity distribution systems met a combined peak demand of 6,299 megawatts ("MW") and its gas distribution system met a peak day demand of 1,462 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 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 primarily determined under cost of service ("COS") regulation. 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. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and 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.
When performance-based rate-setting ("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.
SIGNIFICANT ITEMS
Pending Acquisition of UNS Energy Corporation: In December 2013 Fortis entered into an agreement and plan of merger to acquire UNS Energy Corporation ("UNS Energy") (NYSE:UNS) for US$60.25 per common share in cash, representing an aggregate purchase price of approximately US$4.3 billion, including the assumption of approximately US$1.8 billion of debt on closing. UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through three subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 657,000 electricity and gas customers.
In March 2014 UNS Energy common shareholders approved the acquisition of UNS Energy by Fortis and in April 2014 the U.S. Federal Energy Regulatory Commission ("FERC") approved the transaction. The closing of the acquisition, which is expected to occur by the end of 2014, is subject to certain government and regulatory approvals, including approval by the Arizona Corporation Commission ("ACC"), compliance with other applicable U.S. legislative requirements and the satisfaction of customary closing conditions.
In April 2014 the ACC Staff and other Intervenors filed their direct testimony in the merger proceeding, indicating that they would support the merger subject to certain conditions. Settlement discussions are currently underway between the Corporation, UNS Energy, the ACC Staff and other Intervenors. The ACC Administrative Law Judge ("ALJ") assigned to this matter issued a procedural order adopting the following schedule:
| Settlement agreement filed |
May 16, 2014 |
| Testimony in support of/opposition to settlement agreement |
June 2, 2014 |
| Settlement agreement responsive testimony |
June 13, 2014 |
| Rebuttal testimony (if no settlement) |
May 16, 2014 |
| ACC Staff/Intervenor rebuttal testimony (if no settlement) |
June 2, 2014 |
| UNS Energy and Fortis rejoinder testimony (if no settlement) |
June 13, 2014 |
| ALJ hearing commences |
June 16, 2014 |
The acquisition is consistent with the Corporation's strategy of investing in high-quality regulated utility assets in Canada and the United States and is expected to be accretive to earnings per common share of Fortis in the first full year after closing, excluding one-time acquisition-related costs. At the time of closing the acquisition, the Corporation's consolidated rate base is expected to increase by approximately US$3 billion. The acquisition of UNS Energy will further mitigate 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.
In March 2014 the Corporation secured, as bridge financing for the pending acquisition of UNS Energy, an aggregate of $2 billion non-revolving term credit facilities from a syndicate of banks. The non-revolving term credit facilities are comprised 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.
Convertible Debentures Represented by Installment Receipts: To finance a portion of the pending 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 "Debentures").
The offering of the Debentures consisted of a bought deal placement of $1.594 billion aggregate principal amount of Debentures underwritten by a syndicate of underwriters and the sale of $206 million aggregate principal amount of Debentures to certain institutional investors on a private placement basis (the "Offerings").
The Debentures were sold on an installment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Offerings and the remaining $667 is payable on a date ("Final Installment Date") to be fixed following satisfaction of conditions precedent to the closing of the acquisition of UNS Energy. Prior to the Final Installment Date, the Debentures are represented by Installment Receipts. The Installment Receipts began trading on the Toronto Stock Exchange ("TSX") on January 9, 2014 under the symbol "FTS.IR". The Debentures will not be listed. The Debentures will mature on January 9, 2024 and bear interest at an annual rate of 4% per $1,000 principal amount of Debentures until and including the Final Installment Date, after which the interest rate will be 0%.
If the Final Installment Date occurs prior to the first anniversary of the closing of the Offerings, holders of Debentures who have paid the final installment will be entitled to receive, in addition to the payment of accrued and unpaid interest, an amount equal to the interest that would have accrued from the day following the Final Installment Date to, but excluding, the first anniversary of the closing of the Offerings had the Debentures remained outstanding until such date. Approximately $16 million ($11 million after tax) in interest expense associated with the Debentures was recognized in the first quarter of 2014 and a total of approximately $72 million ($51 million after tax) is expected to be incurred in 2014.
At the option of the holders and provided that payment of the final installment has been made, each Debenture will be 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.
The Debentures will not be redeemable, except that Fortis will redeem the Debentures at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of UNS Energy will not be satisfied; (ii) termination of the acquisition agreement; and (iii) July 2, 2015, if notice of the Final Installment Date has not been given to holders on or before June 30, 2015. In addition, after the Final Installment Date, any Debentures not converted may be redeemed by Fortis at a price equal to their principal amount plus unpaid interest accrued prior to the Final Installment Date. Under the terms of the Installment Receipt Agreement, Fortis agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Installment Date has occurred, the Corporation will at all times maintain availability under its committed revolving corporate credit facility of not less than $600 million to cover the principal amount of the first installment of the Debentures in the event of a mandatory redemption.
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 of the Offerings were approximately $599 million, or $561 million net of issue costs. A significant portion of the net proceeds is cash on hand, while a portion was used to repay borrowings under the Corporation's existing revolving credit facility and for other general corporate purposes, including intercompany loan advances to subsidiaries. The net proceeds of the final installment payment of the Offerings are expected to be, in aggregate, approximately $1.165 billion.
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 months ended March 31, 2014. Earnings for the first quarter of 2014 included $5 million associated with Griffith from normal operations to the date of sale.
Private Placement of US Notes: In March 2014 Fortis priced a private placement to US-based institutional investors of US$500 million in senior unsecured notes. The notes will be 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%. The weighted average term to maturity is approximately 11 years and the weighted average coupon rate is 3.85%. Subject to the satisfaction of customary closing conditions, US$213 million of notes will be issued on June 30, 2014 and US$287 million of notes will be issued on September 15, 2014.
Net proceeds from the sale of the notes will be used to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis maturing on October 30, 2014 and $125 million 5.56% unsecured debentures of a subsidiary maturing on September 15, 2014, and for general corporate purposes, including repayment of US-dollar drawings on the Corporation's committed credit facility.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common share and total shareholder return as the primary measures of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the first quarters ended March 31, 2014 and 2013 are provided in the following table.
| Consolidated Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions, except for common share data) |
2014 |
2013 |
Variance |
|
| Revenue |
1,455 |
1,113 |
342 |
|
| Energy Supply Costs |
679 |
505 |
174 |
|
| Operating Expenses |
319 |
221 |
98 |
|
| Depreciation and Amortization |
148 |
129 |
19 |
|
| Other Income (Expenses), Net |
7 |
6 |
1 |
|
| Finance Charges |
123 |
89 |
34 |
|
| Income Tax Expense |
39 |
30 |
9 |
|
| Earnings from Continuing Operations |
154 |
145 |
9 |
|
| Earnings from Discontinued Operations, Net of Tax |
5 |
- |
5 |
|
| Earnings Before Extraordinary Item |
159 |
145 |
14 |
|
| Extraordinary Gain, Net of Tax |
- |
22 |
(22 |
) |
| Net Earnings |
159 |
167 |
(8 |
) |
| Net Earnings Attributable to: |
|
|
|
|
| |
Non-Controlling Interests |
2 |
2 |
- |
|
| |
Preference Equity Shareholders |
14 |
14 |
- |
|
| |
Common Equity Shareholders |
143 |
151 |
(8 |
) |
| Net Earnings |
159 |
167 |
(8 |
) |
| Earnings per Common Share from Continuing Operations |
|
|
|
|
| |
Basic ($) |
0.65 |
0.67 |
(0.02 |
) |
| |
Diluted ($) |
0.64 |
0.66 |
(0.02 |
) |
| Earnings per Common Share |
|
|
|
|
| |
Basic ($) |
0.67 |
0.79 |
(0.12 |
) |
| |
Diluted ($) |
0.66 |
0.76 |
(0.10 |
) |
| Weighted Average Number of Common Shares Outstanding (# millions) |
213.6 |
192.0 |
21.6 |
|
| Cash Flow from Operating Activities |
265 |
283 |
(18 |
) |
Revenue
The increase in revenue was driven by the acquisition of Central Hudson Gas & Electric Corporation ("Central Hudson"), higher electricity sales and gas volumes, an increase in the base component of rates at most of the regulated utilities, and favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Energy Supply Costs
The increase in energy supply costs was primarily due to the acquisition of Central Hudson and higher electricity sales and gas volumes, which increased fuel, power and natural gas purchases.
Operating Expenses
The increase in operating expenses was primarily due to the acquisition of Central Hudson and general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to the acquisition of Central Hudson and continued investment in energy infrastructure at the Corporation's regulated utilities.
Other Income (Expenses), Net
Other income, net of expenses, for the first quarter of 2014 was comparable to the same period last year.
Finance Charges
The increase in finance charges was primarily due to $16 million in interest expense associated with convertible debentures issued to finance a portion of the pending acquisition of UNS Energy, and the acquisition of Central Hudson, including interest expense on debt issued to complete the financing of the acquisition.
Income Tax Expense
The increase in income tax expense was primarily due to higher earnings before income taxes, driven by the acquisition of Central Hudson, and a decrease in items capitalized for accounting purposes, but expensed for income tax purposes. The increase was partially offset by the recognition of approximately $2 million in income tax expense in the first quarter of 2013 associated with Part VI.1 tax.
Earnings from Discontinued Operations, Net of Tax
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 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 impacts of Griffith, interest expense on the convertible debentures, and the Exploits Partnership, earnings were $149 million compared to $129 million for the same period last year. The increase was driven by earnings of $18 million at Central Hudson, which was acquired in June 2013. Performance at Non-Regulated Fortis Generation was favourably impacted by increased production in Belize due to higher rainfall. Newfoundland Power's earnings were $3 million higher quarter over quarter, mainly related to regulator-approved adjustments, which impacted the timing of quarterly earnings. Earnings at Caribbean Regulated Electric Utilities were $2 million higher compared to the first quarter of 2013, driven by electricity sales growth.
The increases were partially offset by lower earnings at the FortisBC Energy companies and higher Corporate and Other expenses. The first stage of the Generic Cost of Capital ("GCOC") Proceeding in British Columbia reduced the allowed ROE and equity component of capital structure for the benchmark utility, FortisBC Energy Inc. ("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. As a result, a reduction of earnings of approximately $5 million at the FortisBC Energy companies and $1 million at FortisBC Electric related to the first quarter of 2013 was not recognized until the second quarter of 2013. Corporate and Other expenses were $1 million higher quarter over quarter. The increase was primarily due to interest expense on debt issued to complete the financing of the acquisition of Central Hudson, partially offset by a higher income tax recovery.
SEGMENTED RESULTS OF OPERATIONS
| Segmented Net Earnings Attributable to Common Equity Shareholders |
|
| (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
Variance |
|
| Regulated Gas Utilities - Canadian |
|
|
|
|
|
|
| |
FortisBC Energy Companies |
79 |
|
85 |
|
(6 |
) |
| Regulated Gas & Electric Utility - United States |
|
|
|
|
|
|
| |
Central Hudson |
18 |
|
- |
|
18 |
|
| Regulated Electric Utilities - Canadian |
|
|
|
|
|
|
| |
FortisAlberta |
25 |
|
26 |
|
(1 |
) |
| |
FortisBC Electric |
18 |
|
18 |
|
- |
|
| |
Newfoundland Power |
10 |
|
7 |
|
3 |
|
| |
Other Canadian Electric Utilities |
7 |
|
6 |
|
1 |
|
| |
60 |
|
57 |
|
3 |
|
| Regulated Electric Utilities - Caribbean |
5 |
|
3 |
|
2 |
|
| Non-Regulated - Fortis Generation |
6 |
|
24 |
|
(18 |
) |
| Non-Regulated - Non-Utility |
5 |
|
- |
|
5 |
|
| Corporate and Other |
(30 |
) |
(18 |
) |
(12 |
) |
| Net Earnings Attributable to Common Equity Shareholders |
143 |
|
151 |
|
(8 |
) |
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 GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2014 |
2013 |
Variance |
|
| Gas Volumes (petajoules ("PJ")) |
75 |
71 |
4 |
|
| Revenue ($ millions) |
513 |
492 |
21 |
|
| Earnings ($ millions) |
79 |
85 |
(6 |
) |
| |
|
| (1) |
Primarily includes FEI, FortisBC Energy (Vancouver Island) Inc. and FortisBC Energy (Whistler) Inc. |
Gas Volumes
The increase in gas volumes was primarily due to higher average consumption by residential, commercial and transportation customers as a result of colder temperatures.
As at March 31, 2014, the total number of customers served by the FortisBC Energy companies was approximately 962,000, up 6,000 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 regulator-approved deferral mechanisms, changes in consumption levels and the commodity cost of natural gas from those forecast to set residential and commercial customer gas 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 was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers, partially offset by a decrease in the delivery component of customer rates at FEI as a result of the outcome of the GCOC Proceeding.
In May 2013 the FortisBC Energy companies received a regulatory decision on the first stage of the GCOC Proceeding in British Columbia, resulting in a decrease in the allowed ROE and equity component of capital structure at FEI, the benchmark utility, and an interim decrease in the allowed ROEs at FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"), effective January 1, 2013. The cumulative impact of this regulatory decision was recognized in the second quarter of 2013, when the decision was received. In March 2014 the regulatory decision on the second stage of the GCOC Proceeding was received, resulting in an increase in the allowed ROE at FEWI and an increase in the equity component of capital structure at 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. For further details on the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Earnings
The decrease in earnings was mainly due to the lower allowed ROE and equity component of capital structure, effective January 1, 2013. The cumulative impact of the first stage of the GCOC Proceeding was recognized in the second quarter of 2013, when the decision was received, of which approximately $5 million related to the first quarter of 2013. The cumulative impact of the outcome of the second stage of the GCOC Proceeding was recognized in the first quarter of 2014 and did not have a material impact on earnings. Higher effective income taxes also had an unfavourable impact on earnings quarter over quarter.
REGULATED GAS & ELECTRIC UTILITY - UNITED STATES
CENTRAL HUDSON
| Financial Highlights (Unaudited) |
Quarter |
| Period Ended March 31 |
2014 |
| Average US:CDN Exchange Rate (1) |
1.10 |
| Electricity Sales (gigawatt hours ("GWh")) |
1,407 |
| Gas Volumes (PJ) |
10 |
| Revenue ($ millions) |
272 |
| Earnings ($ millions) |
18 |
| |
|
| (1) |
The reporting currency of Central Hudson is the US dollar. |
Electricity Sales & Gas Volumes
Electricity sales for the first quarter were 1,407 gigawatt hours ("GWh") compared to 1,335 GWh for the same period last year. The increase was primarily due to colder temperatures in the first quarter of 2014.
Gas volumes for the quarter were 10 petajoules ("PJ") compared to 9 PJ for the same period last year. The increase was primarily due to colder temperatures in the first quarter of 2014.
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
Revenue for the first quarter was US$247 million compared to US$195 million for the same period last year. The increase in revenue was primarily due to the recovery from customers of higher commodity purchases, which were driven by higher wholesale prices. The increase in electricity sales and gas volumes also had a favourable impact on revenue; however, the increase was largely offset by the impact of regulatory revenue decoupling mechanisms.
Earnings
Earnings for the first quarter were US$16 million compared to US$14 million for the same period last year. The increase in earnings was mainly due to US$2 million in expenses recognized in the first quarter of 2013, as a result of a regulatory order denying the deferral of certain storm-restoration costs incurred in previous years.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2014 |
2013 |
Variance |
|
| Energy Deliveries (GWh) |
4,683 |
4,491 |
192 |
|
| Revenue ($ millions) |
126 |
118 |
8 |
|
| Earnings ($ millions) |
25 |
26 |
(1 |
) |
Energy Deliveries
The increase in energy deliveries was driven by growth in the number of customers and higher average consumption by residential, commercial, and farm and irrigation customers, due to colder temperatures. The total number of customers increased by approximately 9,000 year over year as at March 31, 2014, as a result of favourable economic conditions.
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 was primarily due to an interim increase in customer electricity distribution rates, effective January 1, 2014, and growth in the number of customers. The increase was partially offset by lower net transmission revenue. Approximately $2 million was recognized in the first quarter of 2013 associated with the finalization of 2012 net transmission volume variances.
Earnings
The decrease in earnings was mainly due to lower net transmission revenue of approximately $2 million, partially offset by rate base growth and growth in the number of customers. Earnings associated with rate base growth, however, continue to be tempered by the interim regulatory decision granting 60% of the revenue requirement associated with the capital tracker component of the PBR mechanism.
FORTISBC ELECTRIC (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2014 |
2013 |
Variance |
| Electricity Sales (GWh) |
907 |
891 |
16 |
| Revenue ($ millions) |
95 |
88 |
7 |
| Earnings ($ millions) |
18 |
18 |
- |
| |
|
| (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 increase in electricity sales was primarily due to higher average consumption as a result of colder temperatures in the first quarter of 2014.
Revenue
The increase in revenue was driven by an interim increase in base electricity rates, effective January 1, 2014, and electricity sales growth.
Earnings
Earnings for the first quarter of 2014 were consistent with earnings for the same period last year. The timing of recognition of regulatory deferrals had a favourable impact on earnings quarter over quarter, which was largely offset by a lower allowed ROE. In May 2013 FortisBC Electric received a regulatory decision on the first stage of the GCOC Proceeding in British Columbia, resulting in an interim decrease in the allowed ROE. The cumulative impact of the regulatory decision was recognized in the second quarter of 2013, when the decision was received, of which approximately $1 million related to the first quarter of 2013. In March 2014 the regulatory decision on the second stage of the GCOC Proceeding was received, resulting in no additional changes to FortisBC Electric's allowed ROE or equity component of capital structure. For further details on the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
NEWFOUNDLAND POWER
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2014 |
2013 |
Variance |
| Electricity Sales (GWh) |
2,000 |
1,942 |
58 |
| Revenue ($ millions) |
209 |
197 |
12 |
| Earnings ($ millions) |
10 |
7 |
3 |
Electricity Sales
The increase in electricity sales was primarily due to customer growth and higher average consumption, due to colder temperatures in the first quarter of 2014 and a higher concentration of electric-versus-oil heating in new home construction.
Revenue
The increase in revenue was primarily due to electricity sales growth and an increase in base electricity rates, effective July 1, 2013, as reflected in the 2013/2014 General Rate Application ("GRA") decision received in April 2013. As part of the GRA, customer electricity rates were also rebased, allowing revenue recognition to more closely reflect the seasonality of electricity sales.
Earnings
The increase in earnings was mainly due to the rebasing of customer electricity rates, effective July 1, 2013, as discussed above. As a result, earnings were higher in the first quarter and are expected to be lower in the third quarter. Electricity sales growth also contributed to the increase in earnings. The increase was partially offset by higher operating expenses associated with restoration efforts following the loss of energy supply from Newfoundland and Labrador Hydro and related power interruptions in January 2014.
OTHER CANADIAN ELECTRIC UTILITIES (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2014 |
2013 |
Variance |
| Electricity Sales (GWh) |
716 |
671 |
45 |
| Revenue ($ millions) |
103 |
96 |
7 |
| Earnings ($ millions) |
7 |
6 |
1 |
| |
|
| (1) |
Comprised of Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power. |
Electricity Sales
The increase in electricity sales was driven by higher average consumption by residential and commercial customers in Ontario and on Prince Edward Island ("PEI"), due to colder temperatures, and an increase in the number of customers using electricity for home heating on PEI.
Revenue
The increase in revenue was primarily due to electricity sales growth, the flow through in customer electricity rates of higher energy supply costs at FortisOntario, and an increase in the base component of customer rates at Maritime Electric, effective March 1, 2014. The increase was partially offset by a higher regulatory rate of return adjustment at Maritime Electric in the first quarter of 2014 compared to the same period last year.
Earnings
The increase in earnings was primarily due to higher earnings at FortisOntario as a result of electricity sales growth, partially offset by a slight decrease in earnings at Maritime Electric due to a higher regulatory rate of return adjustment quarter over quarter.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2014 |
2013 |
Variance |
| Average US:CDN Exchange Rate (2) |
1.10 |
1.01 |
0.09 |
| Electricity Sales (GWh) |
180 |
170 |
10 |
| Revenue ($ millions) |
74 |
66 |
8 |
| Earnings ($ millions) |
5 |
3 |
2 |
| |
|
| (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 ("TCU") (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 was primarily due to warmer temperatures on Grand Cayman, which increased air conditioning load, and growth in the number of customers and improvements in tourism on the Turks and Caicos Islands.
Revenue
The increase in revenue was mainly due to approximately $6 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, electricity sales growth and a 1.8% increase in base customer electricity rates at Caribbean Utilities, effective June 1, 2013.
Earnings
The increase in earnings was driven by electricity sales growth. Favourable foreign exchange associated with the translation of US dollar-denominated earnings also contributed to the increase in earnings.
NON-REGULATED - FORTIS GENERATION (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2014 |
2013 |
Variance |
| Energy Sales (GWh) |
99 |
55 |
44 |
| Revenue ($ millions) |
11 |
5 |
6 |
| Earnings ($ millions) |
6 |
24 |
(18) |
| |
|
| (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 increase in energy sales was driven by increased production in Belize, due to higher rainfall. Production in Upstate New York also contributed to the increase, due to a generating unit being returned to service in October 2013.
Revenue
The increase in revenue was driven by higher production in Belize. Revenue was also favourably impacted by increased production in Upstate New York and approximately $1 million of foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings 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. Business development costs of approximately $1 million associated with investigating a potential hydroelectric generating facility reduced earnings in the first quarter of 2014. The decrease in earnings was partially offset by higher production in Belize.
NON-REGULATED - NON-UTILITY (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| ($ millions) |
2014 |
2013 |
Variance |
| Revenue |
54 |
53 |
1 |
| Earnings |
5 |
- |
5 |
| |
|
| (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 2.7 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, Inc. ("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 to the date of sale in March 2014. |
Revenue
Revenue at Fortis Properties for the first quarter of 2014 was comparable to the same period last year.
Earnings
Earnings for the first quarter of 2014 included $5 million associated with Griffith from normal operations to the date of sale. Fortis Properties contributed earnings of less than $0.5 million, comparable with the first quarter of 2013.
CORPORATE AND OTHER (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
Variance |
|
| Revenue |
7 |
|
6 |
|
1 |
|
| Operating Expenses |
5 |
|
3 |
|
2 |
|
| Depreciation and Amortization |
- |
|
1 |
|
(1 |
) |
| Other Income (Expenses), Net |
2 |
|
2 |
|
- |
|
| Finance Charges |
33 |
|
10 |
|
23 |
|
| Income Tax Recovery |
(13 |
) |
(2 |
) |
(11 |
) |
| |
(16 |
) |
(4 |
) |
(12 |
) |
| Preference Share Dividends |
14 |
|
14 |
|
- |
|
| Net Corporate and Other Expenses |
(30 |
) |
(18 |
) |
(12 |
) |
| |
|
| (1) |
Includes Fortis net Corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") and CH Energy Group's corporate-related activities, and the financial results of FHI's wholly owned subsidiary FortisBC Alternative Energy Services Inc. |
The increase in net Corporate and Other expenses was primarily due to an increase in finance charges, partially offset by a higher income tax recovery.
The increase in finance charges was mainly due to: (i) $16 million ($11 million after tax) in interest expense associated with convertible debentures issued to finance a portion of the pending acquisition of UNS Energy; (ii) the acquisition of Central Hudson in June 2013, including the US$325 million notes offering in October 2013 and drawings under the Corporation's committed credit facility; (iii) unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense; and (iv) higher credit facility fees, including amounts related to the Corporation's $2 billion non-revolving term credit facilities secured as bridge financing for the pending acquisition of UNS Energy.
Operating expenses were impacted by a number of items, including general inflationary increases, an increase in consulting fees, and higher employee-related compensation expenses.
The higher income tax recovery was driven by the overall increase in net Corporate and Other expenses and approximately $2 million in income tax expense recognized in the first quarter of 2013 associated with Part VI.1 tax.
Other income, net of expenses, included: (i) a foreign exchange gain of approximately $4 million in the first quarter of 2014 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, compared to approximately $2 million for the same period last year; and (ii) approximately $2 million in expenses in the first quarter of 2014 related to the pending acquisition of UNS Energy, compared to approximately $0.5 million related to the acquisition of Central Hudson for the same period last year.
Preference share dividends associated with the First Preference Shares, Series K issued in July 2013 were offset by the redemption of First Preference Shares, Series C in July 2013 and a decrease in the annual fixed dividend rate on the First Preference Shares, Series G, effective September 2013.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities for the first quarter of 2014 are summarized as follows.
| NATURE OF REGULATION |
| |
|
|
|
Allowed Returns (%) |
|
Supportive Features |
Regulated
Utility |
|
Regulatory
Authority |
Allowed
Common
Equity
(%) |
2012 |
2013 |
2014 |
|
Future or Historical Test Year
Used to Set Customer Rates |
| |
|
|
|
|
ROE |
|
|
|
| FEI |
|
British Columbia Utilities Commission ("BCUC") |
38.5 (1)
|
9.50
|
8.75
|
8.75
|
|
COS/ROE
PBR mechanism for 2014 through 2018 |
| FEVI |
|
BCUC |
41.5 (1)
|
10.00
|
9.25
|
9.25
|
|
ROEs established by the BCUC |
| FEWI |
|
BCUC |
41.5 (1) |
10.00 |
9.50 |
9.50 |
|
|
| |
|
|
|
|
|
|
|
Future Test Year |
| FortisBC Electric |
|
BCUC |
40
|
9.90
|
9.15
|
9.15
|
|
COS/ROE
|
| |
|
|
|
|
|
|
|
PBR mechanism for 2014 through 2018 |
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
ROE established by the BCUC |
| |
|
|
|
|
|
|
|
Future Test Year |
| Central Hudson |
|
New York State Public Service Commission ("PSC") |
48 (2)
|
10.00
|
10.00
|
10.00 (2)
|
|
COS/ROE
|
| |
|
|
|
|
|
|
|
Earnings sharing mechanism effective July 1, 2013: 50%/50% sharing of earnings above the allowed ROE up to 50 basis points above the allowed ROE; and 10%/90% sharing of earnings in excess of 50 basis points above the allowed ROE |
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
ROE established by the PSC |
| |
|
|
|
|
|
|
|
Future Test Year |
| 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 |
| FortisOntario |
|
Ontario Energy Board |
|
|
|
|
|
Canadian Niagara Power - COS/ROE
|
| |
|
Canadian Niagara Power |
40
|
8.01
|
8.93
|
8.93
|
|
Algoma Power - COS/ROE and subject to Rural and Remote Rate |
| |
|
Algoma Power |
40 |
9.85 |
9.85 |
9.85 |
|
Protection program |
| |
|
|
|
|
|
|
|
|
| |
|
Franchise Agreement Cornwall Electric |
|
|
|
|
|
Cornwall Electric - Price cap with commodity cost flow through |
| |
|
|
|
|
|
|
|
Canadian Niagara Power - 2009 |
| |
|
|
|
|
|
|
|
test year for 2009 through 2012; 2013 |
| |
|
|
|
|
|
|
|
test year for 2013 through 2016 |
| |
|
|
|
|
|
|
|
Algoma Power - 2011 test year for 2012 through 2014 |
| |
|
|
|
|
ROA |
|
|
|
| Caribbean Utilities |
|
Electricity Regulatory Authority |
N/A
|
7.25 -
9.25 |
6.50 -
8.50 |
7.00 -
9.00 (4) |
|
COS/ROA
|
| |
|
|
|
|
|
|
|
Rate-cap adjustment mechanism based on published consumer price indices |
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
The Company may apply for a special additional rate to customers in the event of a disaster, including a hurricane. |
| |
|
|
|
|
|
|
|
Historical Test Year |
| Fortis Turks and Caicos |
|
Utilities make annual filings to the Government of theTurks and Caicos Islands |
N/A
|
17.50 (5)
|
17.50 (5)
|
17.50 (5)
|
|
COS/ROA
|
| |
|
|
|
|
|
|
|
If the actual ROA is lower than the allowed ROA, due to additional costs resulting from a hurricane or other event, the utilities may apply for an increase in customer rates in the following year. |
| |
|
|
|
|
|
|
|
Future Test Year |
| |
|
| (1) |
Effective January 1, 2013. For 2012, the allowed deemed equity component of the capital structure was 40%. |
| (2) |
Effective until June 30, 2015 |
| (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) |
Subject to change in June 2014 based on the annual operation of the rate-cap adjustment mechanism |
| (5) |
Amount allowed under licences as it relates to FortisTCI. Amount allowed under licence for TCU is 15%. 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 associated with significant capital investment in recent years. |
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
The following summarizes the significant regulatory decisions and applications for the Corporation's largest regulated utilities in the first quarter of 2014.
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 must receive the consent of the Lieutenant Governor in Council and is expected to be effective on or about 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 ROE of the benchmark utility, FEI, at 8.75% with a 38.5% 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 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 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 equity component of capital structure for FEVI and FEWI at 41.5%, and for FortisBC Electric, reaffirmed the equity component of capital structure 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 ROE, effective January 1, 2013, for FEVI, FortisBC Electric and FEWI is 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 equity component of capital structure for the amalgamated entity will be set the same as the benchmark utility, FEI.
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 |
| FEI |
|
Multi-Year PBR Plan for 2014-2018 |
June 2013 |
|
Second half of 2014 |
| FortisBC Electric |
|
Multi-Year PBR Plan for 2014-2018 |
July 2013 |
|
Second half of 2014 |
| FortisAlberta |
|
Generic Cost of Capital - |
|
|
|
| |
|
2013 and 2014 |
Not applicable |
|
Late 2014 |
| |
|
Capital Tracker Applications - |
|
|
|
| |
|
2013, 2014 and 2015 |
May 2014 |
|
To be determined |
| Central Hudson |
|
General Rate Application for mid-2015 |
Second half of 2014 |
|
First half of 2015 |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2014 and December 31, 2013.
| Significant Changes in the Consolidated Balance Sheets (Unaudited) between March 31, 2014 and December 31, 2013 |
| Balance Sheet Account |
|
Increase/
(Decrease)
($ millions) |
Explanation |
| Cash and cash equivalents |
|
456 |
The increase was driven by cash on hand at the Corporation, due to net proceeds received from the first installment of the Debentures issued in January 2014, and at CH Energy Group, due to net proceeds received from the sale of Griffith in March 2014. |
| Accounts receivable |
|
133 |
The increase was primarily due to the impact of a seasonal increase in sales at Central Hudson, the FortisBC Energy companies and Newfoundland Power, combined with operation of equal payment plans for customers, mainly at the FortisBC Energy companies and Newfoundland Power. |
| Inventories |
|
(68) |
The decrease was primarily due to the normal seasonal reduction of gas in storage at the FortisBC Energy companies, due to higher consumption during the winter months, partially offset by the impact of higher commodity cost of natural gas. |
| Regulatory assets - current and long-term |
|
62 |
The increase was mainly due to higher rate stabilization accounts at the FortisBC Energy companies and Central Hudson, an increase in regulatory deferred income taxes, and the deferral of various other costs, as permitted by the regulators. |
| Assets held for sale |
|
(112) |
The decrease related to the sale of Griffith in March 2014. |
| Utility capital assets |
|
154 |
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. |
| Short-term borrowings |
|
(96) |
The decrease was primarily due to a reduction in borrowings at the FortisBC Energy companies, due to the seasonality of operations and proceeds received from an intercompany loan advance from Fortis, financed by a portion of the proceeds from the Debentures. |
| Regulatory liabilities - current and long-term |
|
87 |
The increase was primarily due to a higher Alberta Electric System Operator charges deferral at FortisAlberta, an increase in rate stabilization accounts at the FortisBC Energy companies and Central Hudson, and an increase in the provision for non-asset retirement obligation removal costs. |
| Convertible debentures represented by installment receipts |
|
599 |
The increase was due to the first installment of the Debentures issued in January 2014. |
| Long-term debt (including current portion) |
|
(46) |
The decrease was mainly due to the repayment of committed credit facility borrowings at FortisBC Electric, the Corporation and FortisAlberta. The decrease was partially offset by the impact of foreign exchange on the translation of US-dollar denominated debt and the issuance of US$30 million unsecured notes at Central Hudson. |
| Shareholders' equity (before non-controlling interests) |
|
138 |
The increase primarily related to: (i) net earnings attributable to common equity shareholders for the three months ended March 31, 2014, less dividends declared on common shares; (ii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans; and (iii) a decrease in accumulated other comprehensive loss. |
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2014, as compared to the same period in 2013, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
Variance |
|
| Cash, Beginning of Period |
72 |
|
154 |
|
(82 |
) |
| Cash Provided by (Used in): |
|
|
|
|
|
|
| |
Operating Activities |
265 |
|
283 |
|
(18 |
) |
| |
Investing Activities |
(110 |
) |
(292 |
) |
182 |
|
| |
Financing Activities |
301 |
|
23 |
|
278 |
|
| Cash, End of Period |
528 |
|
168 |
|
360 |
|
Operating Activities: Cash flow from operating activities was $18 million lower quarter over quarter. The decrease was primarily due to unfavourable changes in working capital, partially offset by favourable changes in long-term regulatory deferral accounts. The unfavourable changes in working capital were mainly related to current regulatory deferral accounts at Maritime Electric and the FortisBC Energy companies and accounts receivable at Central Hudson, partially offset by favourable changes related to accounts payable at FortisAlberta and the FortisBC Energy companies.
Investing Activities: Cash used in investing activities was $182 million lower quarter over quarter. The decrease was primarily due to the sale of Griffith in March 2014 for proceeds of approximately $105 million (US$95 million), combined with the impact of FortisBC Electric's acquisition of electrical utility assets of the City of Kelowna in March 2013 for approximately $55 million.
Lower capital expenditures related to the non-regulated Waneta Expansion hydroelectric generating facility ("Waneta Expansion") and at FortisAlberta were largely offset by capital spending at Central Hudson in the first quarter of 2014 and higher capital expenditures at the FortisBC Energy companies.
Financing Activities: Cash provided by financing activities was $278 million higher for the first quarter compared to the same period last year. The increase was driven by the net proceeds from the first installment of the Corporation's Debentures, higher proceeds from long-term debt and lower repayments of long term debt. The increase was partially offset by higher repayments under committed credit facilities classified as long term and unfavourable changes in short-term borrowings quarter over quarter.
In January 2014 approximately $599 million, or $561 million net of issue costs, was received from the first installment of the Corporation's Debentures, to be used to finance a portion of the pending acquisition of UNS Energy. A significant portion of the net proceeds is cash on hand, while a portion was used to repay borrowings under the Corporation's existing revolving credit facility and for other general corporate purposes, including intercompany loan advances to subsidiaries.
In March 2014 Central Hudson issued US$30 million in long-term debt, the proceeds of which were used to repay maturing long-term debt and for other general corporate purposes.
Repayments of long-term debt and capital lease and finance obligations and net (repayments) borrowings under committed credit facilities for the quarter compared to the same period last year are summarized in the following tables.
| Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited) |
|
| |
Quarter Ended March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
Variance |
|
| FortisBC Energy Companies |
(1 |
) |
(21 |
) |
20 |
|
| Central Hudson |
(8 |
) |
- |
|
(8 |
) |
| Fortis Properties |
(1 |
) |
(18 |
) |
17 |
|
| Other |
(1 |
) |
(1 |
) |
- |
|
| Total |
(11 |
) |
(40 |
) |
29 |
|
| |
|
| |
|
| |
|
| Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited) |
|
| |
Quarter Ended March 31 |
|
| ($ millions) |
2014 |
|
2013 |
Variance |
|
| FortisAlberta |
(20 |
) |
48 |
(68 |
) |
| FortisBC Electric |
(79 |
) |
32 |
(111 |
) |
| Newfoundland Power |
- |
|
21 |
(21 |
) |
| Corporate |
(46 |
) |
35 |
(81 |
) |
| Total |
(145 |
) |
136 |
(281 |
) |
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 approximately $13 million were received in the first quarter of 2014 to finance capital spending related to the Waneta Expansion, compared to $22 million received during the first quarter of 2013.
Common share dividends paid in the first quarter of 2014 were $47 million, net of $22 million of dividends reinvested, compared to $41 million, net of $19 million of dividends reinvested, paid in the same quarter of 2013. The dividend paid per common share for the first quarter of 2014 was $0.32 compared to $0.31 for the first quarter of 2013. The weighted average number of common shares outstanding for the first quarter of 2014 was 213.6 million compared to 192.0 million for the first quarter of 2013.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at March 31, 2014, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2013 Annual MD&A and below, where applicable.
| Contractual Obligations (Unaudited) |
|
Due |
|
|
|
|
Due |
| As at March 31, 2014 |
|
within |
Due in |
Due in |
Due in |
Due in |
after |
| ($ millions) |
Total |
1 year |
year 2 |
year 3 |
year 4 |
year 5 |
5 years |
| Long-term debt |
7,158 |
737 |
129 |
281 |
81 |
306 |
5,624 |
| Interest obligations on long-term debt |
7,277 |
400 |
361 |
340 |
326 |
319 |
5,531 |
| Convertible debentures represented by installment receipts (1) |
599 |
599 |
- |
- |
- |
- |
- |
| Interest obligations on convertible debentures represented by installment receipts (1) |
62 |
62 |
- |
- |
- |
- |
- |
| Government loan obligations |
15 |
- |
10 |
5 |
- |
- |
- |
| Capital lease and finance obligations |
2,365 |
46 |
46 |
47 |
48 |
75 |
2,103 |
| Gas purchase contract obligations (2) |
490 |
356 |
71 |
18 |
15 |
12 |
18 |
| Power purchase obligations: |
|
|
|
|
|
|
|
| |
Central Hudson (3) |
106 |
29 |
27 |
31 |
7 |
3 |
9 |
| |
FortisBC Electric (4) |
24 |
12 |
7 |
3 |
2 |
- |
- |
| |
FortisOntario |
294 |
46 |
50 |
51 |
53 |
54 |
40 |
| |
Maritime Electric |
93 |
41 |
37 |
1 |
1 |
1 |
12 |
| Capital cost |
542 |
21 |
19 |
21 |
19 |
21 |
441 |
| Operating lease obligations |
31 |
6 |
5 |
5 |
5 |
4 |
6 |
| Waneta Partnership promissory note |
72 |
- |
- |
- |
- |
- |
72 |
| Joint-use asset and shared service agreements |
53 |
3 |
3 |
3 |
3 |
2 |
39 |
| Defined benefit pension funding contributions |
68 |
38 |
18 |
9 |
- |
- |
3 |
| Performance Share Unit Plan obligations |
12 |
2 |
5 |
5 |
- |
- |
- |
| Other |
5 |
2 |
- |
- |
- |
- |
3 |
| Total |
19,266 |
2,400 |
788 |
820 |
560 |
797 |
13,901 |
| |
|
| (1) |
To finance a portion of the pending 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 Debentures, refer to the "Significant Items" section of this MD&A. |
| (2) |
Gas purchase contract obligations at the FortisBC Energy companies are based on index prices as at March 31, 2014. Gas purchase contract obligations at Central Hudson are based on tariff rates as at March 31, 2014. |
| (3) |
Includes Central Hudson's contract to purchase 200 MW of installed capacity from May 1, 2014 through April 30, 2017 totalling approximately US$63 million. The New York Independent System Operator ("NYISO") has been authorized by FERC to create a new capacity zone in the Lower Hudson Valley to maintain system reliability and attract investments in new and existing generation, which will be implemented in May 2014. The key terms of the contract provide that Central Hudson will pay the settlement price in the NYISO Capacity Spot Market auction for the relevant month of delivery minus US$0.175 per kilowatt-month, times the contract quantity of the product delivered during the month. |
| (4) |
On May 6, 2014, the BCUC approved FortisBC Electric's new power purchase agreement ("PPA") 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. Amounts associated with the new PPA have not been included in the contractual obligations table. |
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2013 Annual MD&A.
In March 2014 Fortis priced a private placement to US-based institutional investors of US$500 million in senior unsecured notes. For further information on the notes, refer to the "Significant Items" section of this MD&A. Debt and interest obligations associated with these notes have not been included in the Contractual Obligations table above.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program, that is not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 45% equity, including preference shares, and 55% debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure (Unaudited) |
As at |
| |
March 31, 2014 |
December 31, 2013 |
| |
($ millions) |
(%) |
($ millions) |
(%) |
| Total debt and capital lease and finance obligations (net of cash) (1) |
7,724 |
55.7 |
7,716 |
56.2 |
| Preference shares |
1,229 |
8.9 |
1,229 |
9.0 |
| Common shareholders' equity |
4,910 |
35.4 |
4,772 |
34.8 |
| Total (2) |
13,863 |
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 improvement in the capital structure was primarily due to an increase in common shareholders' equity as a result of: (i) net earnings attributable to common equity shareholders for the three months ended March 31, 2014, less dividends declared on common shares; (ii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans; and (iii) a decrease in accumulated other comprehensive loss. Total debt remained substantially unchanged from December 31, 2013. The increase in debt associated with the convertible debentures represented by installment receipts was largely offset by an increase in cash and a decrease in short-term borrowings and long-term debt.
Excluding capital lease and finance obligations, the Corporation's capital structure as at March 31, 2014 was 54.3% debt, 9.1% preference shares and 36.6% 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- / 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. Similarly, S&P revised its outlook on the Corporation to negative from stable. S&P indicated that an outlook revision to stable would likely occur when the Corporation's Debentures are converted to equity.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $237 million in gross consolidated capital expenditures by segment for the first quarter of 2014 is provided in the following table.
| Gross Consolidated Capital Expenditures (Unaudited) (1) |
| Quarter Ended March 31, 2014 |
| ($ millions) |
| |
|
|
|
FortisBC
Energy
Companies |
Central
Hudson |
Fortis
Alberta |
FortisBC
Electric |
Newfoundland
Power |
Other
Regulated
Electric
Utilities -
Canadian |
Regulated
Electric
Utilities -
Caribbean |
Total
Regulated
Utilities |
Non-
Regulated -
Fortis
Generation |
Non-
Regulated -
Non-
Utility |
Total |
| 51 |
21 |
79 |
15 |
18 |
7 |
13 |
204 |
24 |
9 |
237 |
| |
|
| (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 ("AFUDC"). |
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2014 are forecast to be approximately $1.4 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2013 Annual MD&A.
FortisBC has begun preliminary work related to an expansion of its Tilbury liquefied natural gas ("LNG") facility in British Columbia. The Tilbury expansion, which remains subject to certain approvals, is estimated to cost approximately $400 million and is expected to include a second LNG tank and a new liquefier, both to be in service in 2016. FortisBC is pursuing additional LNG investment opportunities, including a pipeline expansion for the proposed Woodfibre LNG site in British Columbia. These additional opportunities are not included in the Corporation's capital expenditure forecast.
Construction of the $900 million Waneta Expansion is ongoing, with an additional $24 million invested in the first quarter of 2014. Approximately $603 million has been invested in the Waneta Expansion since construction began late in 2010. Key construction activities during the first quarter of 2014 were focused on civil construction and equipment installation. Civil construction included forming and casting on concrete at the intake structure, forming of the power tunnel transition and excavation of the tailrace channel. Equipment installation included assembly of the turbine and generator components and installation of powerhouse mechanical and electrical auxiliary systems. In addition, the 230-kilovolt transmission line construction had the conductor installation completed.
Over the five-year period 2014 through 2018, gross consolidated capital expenditures, excluding capital spending at UNS Energy, are expected to exceed $6.5 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 50% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 27% at Canadian Regulated Gas Utilities; 11% at Central Hudson; 5% at Caribbean Regulated Electric Utilities; and the remaining 7% 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 March 31, 2014, management expects consolidated long-term debt maturities and repayments to average approximately $310 million annually over the next five years. 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 March 31, 2014 and are expected to remain compliant throughout 2014.
CREDIT FACILITIES
As at March 31, 2014, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.7 billion, of which $2.4 billion was unused, including $824 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 20% of these facilities. Approximately $2.6 billion of the total credit facilities are committed facilities with maturities ranging from 2014 through 2019.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities (Unaudited) |
|
|
|
|
|
As at |
|
($ millions) |
Regulated
Utilities |
|
Non-
Regulated |
|
Corporate
and Other |
|
March 31,
2014 |
|
December 31,
2013 |
|
| Total credit facilities |
1,555 |
|
13 |
|
1,140 |
|
2,708 |
|
2,695 |
|
| Credit facilities utilized: |
|
|
|
|
|
|
|
|
|
|
| |
Short-term borrowings |
(63 |
) |
(1 |
) |
- |
|
(64 |
) |
(160 |
) |
| |
Long-term debt (including current portion) |
- |
|
- |
|
(175 |
) |
(175 |
) |
(313 |
) |
| Letters of credit outstanding |
(67 |
) |
- |
|
(1 |
) |
(68 |
) |
(66 |
) |
| Credit facilities unused |
1,425 |
|
12 |
|
964 |
|
2,401 |
|
2,156 |
|
As at March 31, 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 February 2014 Maritime Electric's $50 million unsecured revolving credit facility matured and the Company negotiated a new $50 million unsecured committed revolving credit facility, maturing in February 2019.
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 April 2014 FHI extended its $30 million unsecured committed revolving credit facility to mature in May 2015 from May 2014.
For the purpose of bridge financing for the pending acquisition of UNS Energy, in March 2014 the Corporation secured an aggregate of $2 billion non-revolving term credit facilities from a syndicate of banks. The non-revolving term credit facilities are comprised 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. The credit facilities table does not include the $2 billion credit facilities.
As a result of closing the Debentures related to the pending acquisition of UNS Energy, the Corporation agreed to maintain availability under its committed revolving corporate credit facility of not less than $600 million to cover the principal amount of the first installment of the Debentures in the event of a mandatory redemption.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| Financial Instruments (Unaudited) |
As at |
| |
March 31, 2014 |
December 31, 2013 |
($ millions) |
Carrying
Value |
Estimated
Fair Value |
Carrying
Value |
Estimated
Fair Value |
| Waneta Partnership promissory note |
50 |
52 |
50 |
50 |
| Long-term debt, including current portion |
7,158 |
8,329 |
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 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 $112 million as at March 31, 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 effectively 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 loss or gain on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of Central Hudson, Caribbean Utilities, Fortis Turks and Caicos, Belize Electric Company Limited ("BECOL") and FortisUS Energy Corporation is the US dollar.
As at March 31, 2014, the Corporation's corporately issued US$1,033 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 March 31, 2014, the Corporation had approximately US$585 million (December 31, 2013 - US$560 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded 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.
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 $4 million and $2 million during the three months ended March 31, 2014 and 2013, respectively.
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel, electricity and natural gas prices through the use of derivative instruments. The Corporation does not hold or issue derivative instruments for trading purposes and generally limits the use of derivative instruments to those that qualify as accounting or economic hedges. As at March 31, 2014, the Corporation's derivative instruments primarily consisted of electricity swap contracts, gas swap and option contracts, and gas purchase contract premiums. Electricity swap contracts are held by Central Hudson. Gas swap and option contracts, and gas purchase contract premiums are held by the FortisBC Energy companies.
The following table summarizes the Corporation's derivative instruments.
| Derivative Instruments (Unaudited) |
As at |
| |
|
|
|
March 31, |
December 31, |
| |
|
|
|
2014 |
2013 |
Asset (Liability) |
Maturity |
Number of
Contracts |
Volume (1) |
Carrying Value (2)
($ millions) |
Carrying Value (2)
($ millions) |
| Electricity swap contracts |
2017 |
9 |
3,041 |
23 |
10 |
| Natural gas derivatives: |
|
|
|
|
|
| |
Gas swaps and option contracts |
2014 |
5 |
3 |
(6) |
(13) |
| |
Gas purchase contract premiums |
2015 |
34 |
90 |
(5) |
(2) |
| |
|
| (1) |
The electricity swap contracts are in GWh and natural gas derivatives are in PJ. |
| (2) |
Carrying value is estimated fair value. The asset (liability) represents the gross derivatives balance. |
The electricity swap contracts are used by Central Hudson to minimize commodity price volatility for electricity purchases by fixing the effective purchase price of electricity. The fair value of the electricity swap contracts was 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.
The fair values of the electricity swap contracts and natural gas 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. As at March 31, 2014, none of the electricity swap contracts and natural gas derivatives were designated as hedges of electricity and natural gas supply contracts.
The changes in the fair values of the electricity swap contracts and natural gas derivatives are 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 electricity swap contracts is recorded in accounts receivable and other long-term assets and the fair value of the natural gas derivatives is recorded in accounts payable and other current liabilities as at March 31, 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 $68 million as at March 31, 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.
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.
Regulatory Risk: For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Completion of the Acquisition of UNS Energy: The closing of the acquisition of UNS Energy is subject to normal commercial risks that the acquisition will not close on the terms negotiated, or at all. The pending acquisition remains subject to receipt of certain government and regulatory approvals, including approval by the ACC, compliance with other applicable U.S. legislative requirements and the satisfaction of customary closing conditions. The failure to obtain the required approvals or satisfy or waive the conditions may result in the termination of the agreement and plan of merger and the failure to materialize some, or all, of the expected benefits of the acquisition within the time periods anticipated by the Corporation. The realization of such benefits may also be impacted by other factors beyond the control of Fortis. If the closing of the acquisition of UNS Energy does not take place as contemplated, the Corporation could suffer adverse consequences, including the loss of investor confidence.
A substantial delay in obtaining regulatory approvals or the imposition of unfavourable terms and/or conditions in such approvals could have a material adverse effect on the Corporation's ability to complete the acquisition and on the Corporation's or UNS Energy's business, financial condition or results of operations. Fortis intends to complete the acquisition as soon as practicable after obtaining the required regulatory approvals, and satisfying the other required closing conditions. Failure to realize the anticipated benefits of the acquisition of UNS Energy may impact the financial performance of the Corporation.
For the purpose of financing the acquisition, the Corporation completed the $1.8 billion Debenture Offering in January 2014 and obtained an aggregate of $2 billion non-revolving term credit facilities. For further information, refer to the "Significant Items" section of this MD&A.
Failure to obtain sufficient long-term financing at acceptable terms could result in additional financing costs and the failure to materialize some, or all, of the expected benefits of the acquisition.
If a material amount of the final installment is not paid by holders of Debentures, Fortis may be required to draw down additional funds under the $2 billion non-revolving term credit facilities and it may take Fortis longer than anticipated to repay these credit facilities.
Fortis is exposed to foreign exchange risk associated with the acquisition of UNS Energy as the cash consideration for the acquisition is required to be paid in US dollars, while funds raised in the Debenture Offering, which will constitute a significant portion of the funds used to finance the acquisition, are denominated in Canadian dollars. As a result, a strengthening US dollar prior to payment of the Final Installment will increase the purchase price translated in Canadian dollars. In addition, the operations of UNS Energy are conducted in US dollars and, following the acquisition, the consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate.
Fortis also expects to incur a number of costs associated with completing the acquisition. The majority of these costs will be non-recurring expenses and will consist of transaction costs related to the acquisition, including costs related to financing and obtaining regulatory approval. Additional unanticipated costs may be incurred in 2014 related to the acquisition.
Expropriation of Shares in Belize Electricity: A decision is pending from the Belize Court of Appeal regarding the Corporation's appeal of the Belize Supreme Court's dismissal of the Corporation's claim filed in October 2011 challenging the constitutionality of the expropriation of the Corporation's investment in Belize Electricity.
Fortis believes it has a strong, well-positioned case before the Belize Courts 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 otherwise to be paid to Fortis under the legislation expropriating Belize Electricity could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. The book value was $112 million, including foreign exchange impacts, as at March 31, 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 $112 million long-term other asset is not deemed impaired as at March 31, 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.
Fortis continues to control and consolidate the financial statements of BECOL, the Corporation's indirect wholly owned non-regulated hydroelectric generating subsidiary in Belize. As at March 31, 2014, Belize Electricity owed BECOL approximately US$2 million for energy purchases, of which less than US$1 million was overdue. In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity's obligations to BECOL.
Capital Resources and Liquidity Risk - Credit Ratings: The Corporation's credit ratings were affirmed by S&P in April 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 upgraded Central Hudson to 'A2' from 'A3' with a stable outlook in January 2014; and (ii) DBRS confirmed FortisAlberta's credit rating at 'A(low)' and changed the trend to positive from stable in February 2014.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at March 31, 2014, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $1,785 million, up $123 million or 7%, from $1,662 million as at December 31, 2013.
Labour Relations: The collective agreements between customer service employees at the FortisBC Energy companies and FortisBC Electric, and Canadian Office and Professional Employees Union expired on March 31, 2014. Discussions to renew the collective agreements are ongoing.
Power Supply Contract: 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 March 31, 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 in the future on similar terms.
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2014, as applied for in its Multi-Year PBR Plan for 2014 through 2018, the FortisBC Energy companies 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 2014.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2014 from those disclosed in the 2013 Annual MD&A.
Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position 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 is subject to court approval. In February 2014 the Supreme Court of the State of New York, County of New York, issued a Consent Order preliminarily certifying the matter as a class action and providing directions leading to a Settlement Hearing to be held in June 2014.
Following the announcement of the proposed 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 proposed acquisition. The complaints generally allege that the directors of UNS Energy breached their fiduciary duties in connection with the proposed transaction and that UNS Energy, Fortis, FortisUS Inc., and Color Acquisition Sub Inc. aided and abetted that breach. On March 13, 2014, two of the four complaints filed in the Superior Court were dismissed by the plaintiffs. On March 18, 2014, 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. On April 15, 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.
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. The Government of British Columbia has disclosed that its claim includes approximately $15 million in damages as well as pre-judgment interest, but that it has not fully quantified its damages. FortisBC Electric and its insurers continue to defend the claim by the Government of British Columbia. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
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 March 31, 2014, an obligation of US$46 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.
Eltings Corners
Central Hudson owns and operates a maintenance and warehouse facility. In the course of Central Hudson's hazardous waste permit renewal process for this facility, sediment contamination was discovered within the wetland area across the street from the main property. Based on the investigation work completed by Central Hudson, the DEC and Central Hudson agreed in late 2013 that no additional investigation efforts are necessary. As requested by the DEC, Central Hudson submitted a draft Corrective Measures Study scoping document for review by the DEC. The extent of the contamination has been established and approximately US$3 million has been accrued in the consolidated financial statements.
Asbestos Litigation
Prior to the acquisition of CH Energy Group, various asbestos lawsuits had been brought against Central Hudson. While a total of 3,343 asbestos cases have been raised, 1,171 remained pending as at March 31, 2014. Of the cases no longer pending against Central Hudson, 2,017 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 155 cases. The Company is presently unable to assess the validity of the remaining asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2012 through March 31, 2014. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results |
Net Earnings |
|
|
| (Unaudited) |
Attributable to |
|
|
| |
|
Common Equity |
|
|
| |
Revenue |
Shareholders |
Earnings per Common Share |
| Quarter Ended |
($ millions) |
($ millions) |
Basic ($) |
Diluted ($) |
| 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 |
| September 30, 2012 |
714 |
45 |
0.24 |
0.24 |
| June 30, 2012 |
792 |
62 |
0.33 |
0.33 |
The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity 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.
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. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
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 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 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 Other Canadian Electric Utilities. 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 Other Canadian Electric Utilities, the decrease was primarily due to the impact of the cumulative return adjustment on smart meter investments at FortisOntario in 2012. Corporate and Other expenses were comparable quarter over quarter.
September 2013/September 2012: Net earnings attributable to common equity shareholders were $48 million, or $0.23 per common share, for the third quarter of 2013 compared to earnings of $45 million, or $0.24 per common share, for the third quarter of 2012. Results for the third quarter of 2013 were impacted by the acquisition of CH Energy Group. Central Hudson contributed $12 million to earnings for the third quarter of 2013 and Griffith incurred a net loss of approximately $2.5 million. Due to the common share offering and financing costs associated with the acquisition, earnings per common share for the third quarter of 2013 were not materially impacted by the acquisition of CH Energy Group. Earnings for the third quarter of 2013 were favourably impacted by increased non-regulated hydroelectric generation in Belize, due to higher rainfall, and lower Corporate expenses. Lower Corporate expenses were primarily due to a higher income tax recovery, resulting from the release of income tax provisions in the third quarter of 2013 and the recognition of income tax expense associated with Part VI.1 tax in the third quarter of 2012, and a lower foreign exchange loss, partially offset by higher preference share dividends and redemption costs. The increase in earnings was partially offset by lower contribution from the FortisBC Energy companies, FortisBC Electric, FortisAlberta and Newfoundland Power. At the FortisBC Energy companies, lower earnings were primarily due to higher operating and maintenance expenses, and decreases in the allowed ROE and the equity component of the capital structure as a result of the regulatory decision related to the first stage of the GCOC Proceeding in British Columbia, partially offset by rate base growth. Decreased earnings at FortisBC Electric were mainly due to a decrease in the interim allowed ROE as a result of the regulatory decision related to the first stage of the GCOC Proceeding in British Columbia, lower pole-attachment revenue and higher effective income taxes, partially offset by rate base growth and lower-than-expected finance charges. At FortisAlberta, lower net transmission revenue and $1 million of costs related to flooding in southern Alberta in June 2013 were largely offset by rate base growth, customer growth and timing of operating expenses. Decreased earnings at Newfoundland Power due to the reversal of statute-barred Part VI.1 tax in the third quarter of 2012 were partially offset by rate base growth and lower storm-related costs.
June 2013/June 2012: Net earnings attributable to common equity shareholders were $54 million, or $0.28 per common share, for the second quarter of 2013 compared to earnings of $62 million, or $0.33 per common share, for the second quarter of 2012. 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 CH Energy Group, compared to $3 million of acquisition-related expenses in the second quarter of 2012. 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. In the second quarter of 2012, earnings were reduced by income tax expenses of $3 million associated with Part VI.1 tax. Excluding the above-noted acquisition-related and Part VI.1 tax impacts, net earnings for the second quarter of 2013 were $61 million compared to $68 million for the second quarter of 2012. The decrease in earnings was mainly due to lower contribution from the FortisBC Energy companies, FortisAlberta and FortisBC Electric, and decreased non-regulated hydroelectric production in Belize due to lower rainfall, partially offset by lower Corporate expenses. Earnings at the FortisBC Energy companies and FortisBC Electric were reduced by $8 million and $2 million, respectively, as a result of the regulatory decision related to the first stage of the GCOC Proceeding in British Columbia, which was received in the second quarter of 2013. At the FortisBC Energy companies, earnings contribution from rate base growth was largely offset by lower gas transportation volumes. FortisAlberta's earnings decreased due to lower net transmission revenue and timing of the recognition of a regulatory decision in 2012 impacting depreciation, partially offset by the timing of operating expenses, rate base growth and customer growth. At FortisBC Electric, lower-than-expected finance charges, rate base growth and higher capitalized AFUDC favourably impacted earnings. Lower Corporate expenses were primarily due to the favourable impact of the release of income tax provisions in the second quarter of 2013, a higher foreign exchange gain and lower finance charges, partially offset by higher preference share dividends.
OUTLOOK
Fortis is focused on closing the UNS Energy acquisition by the end of 2014. The acquisition is consistent with the Corporation's strategy of investing in high-quality regulated utility assets in Canada and the United States and is expected to be accretive to earnings per common share of Fortis in the first full year after closing, excluding one-time acquisition-related costs. The acquisition lessens the 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.
At the time of closing the acquisition of UNS Energy, the Corporation's consolidated rate base is expected to increase by approximately US$3 billion, and Fortis utilities will serve more than 3,000,000 electricity and gas customers.
Over the five-year period 2014 through 2018, the Corporation's capital program is expected to exceed $6.5 billion. Additionally, UNS Energy has forecast that its capital program for 2015 through 2018 will be approximately $1.5 billion (US$1.4 billion).
Following the closing of the acquisition of UNS Energy, regulated utilities in the United States will represent approximately one-third of total assets, and regulated utilities and non-regulated hydroelectric generation assets will comprise approximately 97% of the Corporation's total assets.
The Corporation expects earnings per common share growth in 2015 and beyond as a result of contributions from the Central Hudson and UNS Energy acquisitions, and our capital program, including the completion of the Waneta Expansion in 2015 and the Tilbury LNG facility expansion in 2016. This growth will support continuing growth in dividends.
OUTSTANDING SHARE DATA
As at May 7, 2014, the Corporation had issued and outstanding approximately 214.5 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 1.8 million Installment Receipts. 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 represented by installment receipts were converted as at May 7, 2014 is as follows.
| Conversion of Securities into Common Shares (Unaudited) |
As at May 7, 2014
|
Number of
Common Shares |
| Security |
(millions) |
| Stock Options |
5.6 |
| First Preference Shares, Series E |
6.5 |
| Convertible Debentures Represented by Installment Receipts |
58.6 |
| Total |
70.7 |
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 months ended March 31, 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) |
| |
| |
March 31, |
|
December 31, |
|
| |
2014 |
|
2013 |
|
| |
|
|
|
|
|
| ASSETS |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Current assets |
|
|
|
|
|
|
| Cash and cash equivalents |
$ |
528 |
|
$ |
72 |
|
| Accounts receivable |
|
865 |
|
|
732 |
|
| Prepaid expenses |
|
45 |
|
|
45 |
|
| Inventories |
|
75 |
|
|
143 |
|
| Regulatory assets (Note 3) |
|
179 |
|
|
150 |
|
| Assets held for sale (Note 11) |
|
- |
|
|
112 |
|
| Deferred income taxes |
|
22 |
|
|
42 |
|
| |
|
1,714 |
|
|
1,296 |
|
| Other assets |
|
287 |
|
|
246 |
|
| Regulatory assets (Note 3) |
|
1,705 |
|
|
1,672 |
|
| Deferred income taxes |
|
23 |
|
|
7 |
|
| Utility capital assets |
|
11,772 |
|
|
11,618 |
|
| Non-utility capital assets |
|
652 |
|
|
649 |
|
| Intangible assets |
|
340 |
|
|
345 |
|
| Goodwill |
|
2,097 |
|
|
2,075 |
|
| |
|
|
|
|
|
|
| |
$ |
18,590 |
|
$ |
17,908 |
|
| |
|
|
|
|
|
|
| LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Current liabilities |
|
|
|
|
|
|
| Short-term borrowings (Note 18) |
$ |
64 |
|
$ |
160 |
|
| Accounts payable and other current liabilities |
|
978 |
|
|
957 |
|
| Regulatory liabilities (Note 3) |
|
149 |
|
|
140 |
|
| Convertible debentures represented by installment receipts (Note 4) |
|
599 |
|
|
- |
|
| Current installments of long-term debt |
|
737 |
|
|
780 |
|
| Current installments of capital lease and finance obligations |
|
7 |
|
|
7 |
|
| Liabilities associated with assets held for sale (Note 11) |
|
- |
|
|
32 |
|
| Deferred income taxes |
|
8 |
|
|
8 |
|
| |
|
2,542 |
|
|
2,084 |
|
| Other liabilities |
|
616 |
|
|
627 |
|
| Regulatory liabilities (Note 3) |
|
980 |
|
|
902 |
|
| Deferred income taxes |
|
1,075 |
|
|
1,078 |
|
| Long-term debt |
|
6,421 |
|
|
6,424 |
|
| Capital lease and finance obligations |
|
424 |
|
|
417 |
|
| |
|
12,058 |
|
|
11,532 |
|
| |
|
|
|
|
|
|
| Shareholders' equity |
|
|
|
|
|
|
| Common shares (1) (Note 5) |
|
3,816 |
|
|
3,783 |
|
| Preference shares |
|
1,229 |
|
|
1,229 |
|
| Additional paid-in capital |
|
17 |
|
|
17 |
|
| Accumulated other comprehensive loss |
|
(41 |
) |
|
(72 |
) |
| Retained earnings |
|
1,118 |
|
|
1,044 |
|
| |
|
6,139 |
|
|
6,001 |
|
| Non-controlling interests |
|
393 |
|
|
375 |
|
| |
|
6,532 |
|
|
6,376 |
|
| |
|
|
|
|
|
|
| |
$ |
18,590 |
|
$ |
17,908 |
|
| |
|
| (1) |
No par value. Unlimited authorized shares; 214.3 million and 213.2 million issued and outstanding as at March 31, 2014 and December 31, 2013, respectively |
| |
| Commitments and Contingencies (Notes 19 and 21, respectively) |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| Fortis Inc. |
| Consolidated Statements of Earnings (Unaudited) |
| For the three months ended March 31 |
| (in millions of Canadian dollars, except per share amounts) |
| |
| |
Quarter Ended |
| |
2014 |
2013 |
| |
|
|
|
|
| Revenue |
$ |
1,455 |
$ |
1,113 |
| Expenses |
|
|
|
|
| |
Energy supply costs |
|
679 |
|
505 |
| |
Operating |
|
319 |
|
221 |
| |
Depreciation and amortization |
|
148 |
|
129 |
| |
|
1,146 |
|
855 |
| Operating income |
|
309 |
|
258 |
| Other income (expenses), net (Note 8) |
|
7 |
|
6 |
| Finance charges (Note 9) |
|
123 |
|
89 |
| Earnings before income taxes, discontinued operations and extraordinary item |
|
193 |
|
175 |
| Income tax expense (Note 10) |
|
39 |
|
30 |
| Earnings from continuing operations |
|
154 |
|
145 |
| Earnings from discontinued operations, net of tax (Note 11) |
|
5 |
|
- |
| Earnings before extraordinary item |
|
159 |
|
145 |
| Extraordinary gain, net of tax (Note 12) |
|
- |
|
22 |
| Net earnings |
$ |
159 |
$ |
167 |
| |
|
|
|
|
| Net earnings attributable to: |
|
|
|
|
| |
Non-controlling interests |
$ |
2 |
$ |
2 |
| |
Preference equity shareholders |
|
14 |
|
14 |
| |
Common equity shareholders |
|
143 |
|
151 |
| |
$ |
159 |
$ |
167 |
| |
|
|
|
|
| Earnings per common share from continuing operations (Note 13) |
|
|
|
|
| |
Basic |
$ |
0.65 |
$ |
0.67 |
| |
Diluted |
$ |
0.64 |
$ |
0.66 |
| Earnings per common share (Note 13) |
|
|
|
|
| |
Basic |
$ |
0.67 |
$ |
0.79 |
| |
Diluted |
$ |
0.66 |
$ |
0.76 |
| |
|
|
|
|
| |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| Fortis Inc. |
| Consolidated Statements of Comprehensive Income (Unaudited) |
| For the three months ended March 31 |
| (in millions of Canadian dollars) |
| |
| |
Quarter Ended |
| |
2014 |
2013 |
| |
|
|
|
|
| Net earnings |
$ |
159 |
$ |
167 |
| |
|
|
|
|
| Other comprehensive income |
|
|
|
|
| Unrealized foreign currency translation gains, net of hedging activities and tax |
|
30 |
|
2 |
| Unrealized employee future benefits gains, net of tax |
|
1 |
|
1 |
| |
|
31 |
|
3 |
| Comprehensive income |
$ |
190 |
$ |
170 |
| |
|
|
|
|
| Comprehensive income attributable to: |
|
|
|
|
| |
Non-controlling interests |
$ |
2 |
$ |
2 |
| |
Preference equity shareholders |
|
14 |
|
14 |
| |
Common equity shareholders |
|
174 |
|
154 |
| |
$ |
190 |
$ |
170 |
| |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| Fortis Inc. |
| Consolidated Statements of Cash Flows (Unaudited) |
| For the three months ended March 31 |
| (in millions of Canadian dollars) |
| |
| |
Quarter Ended |
|
| |
2014 |
|
2013 |
|
| |
|
|
|
|
|
|
| Operating activities |
|
|
|
|
|
|
| Net earnings |
$ |
159 |
|
$ |
167 |
|
| Adjustments to reconcile net earnings to net cash provided by operating activities: |
|
|
|
|
|
|
| |
Depreciation - capital assets |
|
130 |
|
|
113 |
|
| |
Amortization - intangible assets |
|
13 |
|
|
12 |
|
| |
Amortization - other |
|
5 |
|
|
4 |
|
| |
Deferred income tax recovery |
|
(7 |
) |
|
(11 |
) |
| |
Accrued employee future benefits |
|
(9 |
) |
|
(1 |
) |
| |
Equity component of allowance for funds used during construction (Note 8) |
|
(2 |
) |
|
(3 |
) |
| |
Other |
|
1 |
|
|
(10 |
) |
| Change in long-term regulatory assets and liabilities |
|
30 |
|
|
(6 |
) |
| Change in non-cash operating working capital (Note 15) |
|
(55 |
) |
|
18 |
|
| |
|
265 |
|
|
283 |
|
| |
|
|
|
|
|
|
| Investing activities |
|
|
|
|
|
|
| Change in other assets and other liabilities |
|
3 |
|
|
5 |
|
| Capital expenditures - utility capital assets |
|
(221 |
) |
|
(233 |
) |
| Capital expenditures - non-utility capital assets |
|
(9 |
) |
|
(13 |
) |
| Capital expenditures - intangible assets |
|
(7 |
) |
|
(7 |
) |
| Contributions in aid of construction |
|
18 |
|
|
10 |
|
| Proceeds on sale of assets (Note 11) |
|
106 |
|
|
1 |
|
| Business acquisition, net of cash acquired |
|
- |
|
|
(55 |
) |
| |
|
(110 |
) |
|
(292 |
) |
| |
|
|
|
|
|
|
| Financing activities |
|
|
|
|
|
|
| Change in short-term borrowings |
|
(98 |
) |
|
(48 |
) |
| Proceeds from convertible debentures represented by installment receipts, net of issue costs (Note 4) |
|
561 |
|
|
- |
|
| Proceeds from long-term debt, net of issue costs |
|
33 |
|
|
- |
|
| Repayments of long-term debt and capital lease and finance obligations |
|
(11 |
) |
|
(40 |
) |
| Net (repayments) borrowings under committed credit facilities |
|
(145 |
) |
|
136 |
|
| Advances from non-controlling interests |
|
13 |
|
|
22 |
|
| Issue of common shares, net of costs and dividends reinvested |
|
11 |
|
|
10 |
|
| Dividends |
|
|
|
|
|
|
| |
Common shares, net of dividends reinvested |
|
(47 |
) |
|
(41 |
) |
| |
Preference shares |
|
(14 |
) |
|
(14 |
) |
| |
Subsidiary dividends paid to non-controlling interests |
|
(2 |
) |
|
(2 |
) |
| |
|
301 |
|
|
23 |
|
| |
|
|
|
|
|
|
| Change in cash and cash equivalents |
|
456 |
|
|
14 |
|
| |
|
|
|
|
|
|
| Cash and cash equivalents, beginning of period |
|
72 |
|
|
154 |
|
| |
|
|
|
|
|
|
| Cash and cash equivalents, end of period |
$ |
528 |
|
$ |
168 |
|
| |
| Supplementary Information to Consolidated Statements of Cash Flows (Note 15) |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| Fortis Inc. |
| Consolidated Statements of Changes in Equity (Unaudited) |
| For the three months ended March 31 |
| (in millions of Canadian dollars) |
| |
| |
Common
Shares |
Preference
Shares |
Additional
Paid-in
Capital |
|
Accumulated
Other
Comprehensive
Loss |
|
Retained
Earnings |
|
Non-
Controlling
Interests |
|
Total
Equity |
|
| |
(Note 5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at January 1, 2014 |
$ |
3,783 |
$ |
1,229 |
$ |
17 |
|
$ |
(72 |
) |
$ |
1,044 |
|
$ |
375 |
|
$ |
6,376 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net earnings |
|
- |
|
- |
|
- |
|
|
- |
|
|
157 |
|
|
2 |
|
|
159 |
|
| Other comprehensive income |
|
- |
|
- |
|
- |
|
|
31 |
|
|
- |
|
|
- |
|
|
31 |
|
| Common share issues |
|
33 |
|
- |
|
(1 |
) |
|
- |
|
|
- |
|
|
- |
|
|
32 |
|
| Stock-based compensation |
|
- |
|
- |
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
1 |
|
| Advances from non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
13 |
|
|
13 |
|
| Foreign currency translation impacts |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
5 |
|
|
5 |
|
| Subsidiary dividends paid to non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
(2 |
) |
|
(2 |
) |
| Dividends declared on common shares ($0.32 per share) |
|
- |
|
- |
|
- |
|
|
- |
|
|
(69 |
) |
|
- |
|
|
(69 |
) |
| Dividends declared on preference shares |
|
- |
|
- |
|
- |
|
|
- |
|
|
(14 |
) |
|
- |
|
|
(14 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at March 31, 2014 |
$ |
3,816 |
$ |
1,229 |
$ |
17 |
|
$ |
(41 |
) |
$ |
1,118 |
|
$ |
393 |
|
$ |
6,532 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at January 1, 2013 |
$ |
3,121 |
$ |
1,108 |
$ |
15 |
|
$ |
(96 |
) |
$ |
952 |
|
$ |
310 |
|
$ |
5,410 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net earnings |
|
- |
|
- |
|
- |
|
|
- |
|
|
165 |
|
|
2 |
|
|
167 |
|
| Other comprehensive income |
|
- |
|
- |
|
- |
|
|
3 |
|
|
- |
|
|
- |
|
|
3 |
|
| Common share issues |
|
28 |
|
- |
|
(1 |
) |
|
- |
|
|
- |
|
|
- |
|
|
27 |
|
| Stock-based compensation |
|
- |
|
- |
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
1 |
|
| Advances from non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
22 |
|
|
22 |
|
| Foreign currency translation impacts |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
1 |
|
|
1 |
|
| Subsidiary dividends paid to non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
(2 |
) |
|
(2 |
) |
| Dividends declared on common shares ($0.31 per share) |
|
- |
|
- |
|
- |
|
|
- |
|
|
(60 |
) |
|
- |
|
|
(60 |
) |
| Dividends declared on preference shares |
|
- |
|
- |
|
- |
|
|
- |
|
|
(14 |
) |
|
- |
|
|
(14 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at March 31, 2013 |
$ |
3,149 |
$ |
1,108 |
$ |
15 |
|
$ |
(93 |
) |
$ |
1,043 |
|
$ |
333 |
|
$ |
5,555 |
|
| |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| FORTIS INC. |
| NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS |
| For the three months ended March 31, 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.
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities are as follows:
- 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 Gas & Electric Utility - United States: Includes Central Hudson Gas & Electric Corporation ("Central Hudson"), which was acquired by Fortis as part of the acquisition of CH Energy Group, Inc. ("CH Energy Group") in June 2013.
- Regulated Electric Utilities - Canadian: Comprised of FortisAlberta, FortisBC Electric, Newfoundland Power, and Other Canadian Electric Utilities (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 2.7 million square feet of commercial office and retail space, primarily in Atlantic Canada.
- Griffith: Comprised primarily of Griffith Energy Services, Inc. ("Griffith"), which supplies petroleum products and related services in the Mid-Atlantic Region of the United States. Griffith was acquired by Fortis as part of the acquisition of CH Energy Group in June 2013 and was sold in March 2014 (Note 11).
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.
The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated FortisBC Holdings Inc. ("FHI") and CH Energy Group. Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. ("FAES"). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.
PENDING ACQUISITION
In December 2013 Fortis entered into an agreement and plan of merger to acquire UNS Energy Corporation ("UNS Energy") (NYSE:UNS) for US$60.25 per common share in cash, representing an aggregate purchase price of approximately US$4.3 billion, including the assumption of approximately US$1.8 billion of debt on closing. In March 2014 UNS Energy common shareholders approved the acquisition of UNS Energy by Fortis and in April 2014 the U.S. Federal Energy Regulatory Commission ("FERC") approved the transaction. The closing of the acquisition, which is expected to occur by the end of 2014, is subject to certain government and regulatory approvals, including approval by the Arizona Corporation Commission, compliance with other applicable U.S. legislative requirements and the satisfaction of customary closing conditions (Notes 4 and 21).
UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona, engaged through three subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 657,000 electricity and gas customers.
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 gas and electricity 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. Given the diversified group of companies, 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 recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2014.
An evaluation of subsequent events through to May 7, 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 March 31, 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. 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 applied for in its Multi-Year Performance-Based Ratemaking Plan for 2014 through 2018, the FortisBC Energy companies 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.
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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 2014.
3. 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 |
|
| |
March 31, |
|
December 31, |
|
| ($ millions) |
2014 |
|
2013 |
|
| Regulatory assets |
|
|
|
|
| Deferred income taxes |
845 |
|
833 |
|
| Employee future benefits |
425 |
|
440 |
|
| Rate stabilization accounts |
116 |
|
85 |
|
| Deferred lease costs |
85 |
|
76 |
|
| Deferred energy management costs |
79 |
|
76 |
|
| Manufactured gas plant ("MGP") site remediation deferral |
57 |
|
47 |
|
| Deferred operating overhead costs |
46 |
|
43 |
|
| Deferred net losses on disposal of utility capital assets and intangible assets |
41 |
|
35 |
|
| Income taxes recoverable on other post-employment benefit ("OPEB") plans |
24 |
|
24 |
|
| Customer Care Enhancement Project cost deferral |
20 |
|
21 |
|
| Carrying charges - employee future benefits |
16 |
|
14 |
|
| Natural gas for transportation incentives |
16 |
|
8 |
|
| Whistler pipeline contribution deferral |
13 |
|
13 |
|
| Alternative energy projects cost deferral |
12 |
|
11 |
|
| Other regulatory assets |
89 |
|
96 |
|
| Total regulatory assets |
1,884 |
|
1,822 |
|
| Less: current portion |
(179 |
) |
(150 |
) |
| Long-term regulatory assets |
1,705 |
|
1,672 |
|
| |
|
|
| |
|
|
| |
|
|
| |
As at |
|
| |
March 31, |
|
December 31, |
|
| ($ millions) |
2014 |
|
2013 |
|
| Regulatory liabilities |
|
|
|
|
| Non-asset retirement obligation removal cost provision |
574 |
|
563 |
|
| Rate stabilization accounts |
200 |
|
177 |
|
| Alberta Electric System Operator charges deferral |
105 |
|
73 |
|
| Employee future benefits |
58 |
|
55 |
|
| Deferred income taxes |
47 |
|
45 |
|
| Customer and community benefits obligation |
24 |
|
23 |
|
| Carrying charges - employee future benefits |
18 |
|
16 |
|
| Meter reading and customer service variance deferral |
17 |
|
17 |
|
| Rate base impact of tax repair project |
14 |
|
13 |
|
| Other regulatory liabilities |
72 |
|
60 |
|
| Total regulatory liabilities |
1,129 |
|
1,042 |
|
| Less: current portion |
(149 |
) |
(140 |
) |
| Long-term regulatory liabilities |
980 |
|
902 |
|
4. CONVERTIBLE DEBENTURES REPRESENTED BY INSTALLMENT RECEIPTS
To finance a portion of the pending 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 "Debentures").
The offering of the Debentures consisted of a bought deal placement of $1.594 billion aggregate principal amount of Debentures underwritten by a syndicate of underwriters and the sale of $206 million aggregate principal amount of Debentures to certain institutional investors on a private placement basis (the "Offerings").
The Debentures were sold on an installment basis at a price of $1,000 per Debenture, of which $333 was paid on closing of the Offerings and the remaining $667 is payable on a date ("Final Installment Date") to be fixed following satisfaction of conditions precedent to the closing of the acquisition of UNS Energy. Prior to the Final Installment Date, the Debentures are represented by Installment Receipts. The Installment Receipts began trading on the Toronto Stock Exchange ("TSX") on January 9, 2014 under the symbol "FTS.IR". The Debentures will not be listed. The Debentures will mature on January 9, 2024 and bear interest at an annual rate of 4% per $1,000 principal amount of Debentures until and including the Final Installment Date, after which the interest rate will be 0%.
If the Final Installment Date occurs prior to the first anniversary of the closing of the Offerings, holders of Debentures who have paid the final installment will be entitled to receive, in addition to the payment of accrued and unpaid interest, an amount equal to the interest that would have accrued from the day following the Final Installment Date to, but excluding, the first anniversary of the closing of the Offerings had the Debentures remained outstanding until such date. Approximately $16 million ($11 million after tax) in interest expense associated with the Debentures was recognized in the first quarter of 2014 and a total of approximately $72 million ($51 million after tax) is expected to be incurred in 2014 (Notes 9 and 19).
At the option of the holders and provided that payment of the final installment has been made, each Debenture will be 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.
The Debentures will not be redeemable, except that Fortis will redeem the Debentures at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of UNS Energy will not be satisfied; (ii) termination of the acquisition agreement; and (iii) July 2, 2015, if notice of the Final Installment Date has not been given to holders on or before June 30, 2015. In addition, after the Final Installment Date, any Debentures not converted may be redeemed by Fortis at a price equal to their principal amount plus unpaid interest accrued prior to the Final Installment Date. Under the terms of the Installment Receipt Agreement, Fortis agreed that until such time as the Debentures have been redeemed in accordance with the foregoing or the Final Installment Date has occurred, the Corporation will at all times maintain availability under its committed revolving corporate credit facility of not less than $600 million to cover the principal amount of the first installment of the Debentures in the event of a mandatory redemption.
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 of the Offerings were approximately $599 million, or $561 million net of issue costs. A significant portion of the net proceeds is cash on hand, while a portion was used to repay borrowings under the Corporation's existing revolving credit facility and for other general corporate purposes, including intercompany loan advances to subsidiaries. The net proceeds of the final installment payment of the Offerings are expected to be, in aggregate, approximately $1.165 billion.
5. COMMON SHARES
Common shares issued during the period were as follows:
| |
Quarter Ended |
| |
March 31, 2014 |
|
Number of
Shares |
Amount |
| |
(in thousands) |
($ millions) |
| Balance, beginning of period |
213,165 |
3,783 |
| |
Dividend Reinvestment Plan |
731 |
22 |
| |
Consumer Share Purchase Plan |
11 |
- |
| |
Employee Share Purchase Plan |
173 |
5 |
| |
Stock Option Plans |
199 |
6 |
| Balance, end of period |
214,279 |
3,816 |
6. STOCK-BASED COMPENSATION PLANS
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 January 2014, 155,133 Performance Share Units ("PSUs") were granted to senior management of the Corporation and its subsidiaries under the 2013 PSU Plan, representing a component of the long-term incentives. 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 March 2014, 33,559 PSUs, representing two-thirds of the vested PSUs, were paid out to the President and 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 President and CEO satisfying two of the three payment requirements, as determined by the Human Resources Committee of the Board of Directors of Fortis.
In February 2014, the Corporation granted 925,172 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 of $30.73. The options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan. The fair value of each option granted was $3.53 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
| Dividend yield (%) |
3.81 |
| Expected volatility (%) |
20.3 |
| Risk-free interest rate (%) |
1.69 |
| Weighted average expected life (years) |
5.5 |
For the three months ended March 31, 2014, stock-based compensation expense of approximately $2 million was recognized ($1 million for the three months ended March 31, 2013).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group registered retirement savings plans, for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following table.
| |
Quarter Ended March 31 |
|
| |
Defined Benefit
Pension Plans |
|
OPEB Plans |
|
| ($ millions) |
2014 |
|
2013 |
|
2014 |
|
2013 |
|
| Components of net benefit cost: |
|
|
|
|
|
|
|
|
| Service costs |
10 |
|
8 |
|
3 |
|
2 |
|
| Interest costs |
21 |
|
12 |
|
4 |
|
3 |
|
| Expected return on plan assets |
(24 |
) |
(13 |
) |
(2 |
) |
- |
|
| Amortization of actuarial losses |
7 |
|
7 |
|
2 |
|
2 |
|
| Amortization of past service credits/plan amendments |
- |
|
- |
|
(2 |
) |
(1 |
) |
| Regulatory adjustments |
2 |
|
(3 |
) |
2 |
|
- |
|
| Net benefit cost |
16 |
|
11 |
|
7 |
|
6 |
|
For the three months ended March 31, 2014, the Corporation expensed $5 million ($4 million for the three months ended March 31, 2013) related to defined contribution pension plans.
8. OTHER INCOME (EXPENSES), NET
| |
Quarter Ended |
| |
March 31 |
| ($ millions) |
2014 |
|
2013 |
| Equity component of allowance for funds used during construction ("AFUDC") |
2 |
|
3 |
| Net foreign exchange gain |
4 |
|
2 |
| Interest income |
4 |
|
1 |
| Other |
(1 |
) |
- |
| Acquisition-related expenses |
(2 |
) |
- |
| |
7 |
|
6 |
The net foreign exchange gain for the three months ended March 31, 2014 and 2013 is related 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 18 and 20).
The acquisition-related expenses are associated with the pending acquisition of UNS Energy (Note 1).
9. FINANCE CHARGES
| |
|
Quarter Ended |
|
| |
|
March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
| Interest |
- Long-term debt and capital lease and finance obligations |
111 |
|
94 |
|
| |
- Convertible debentures represented by installment receipts |
16 |
|
- |
|
| |
- Short-term borrowings |
2 |
|
2 |
|
| Debt component of AFUDC |
(6 |
) |
(7 |
) |
| |
|
123 |
|
89 |
|
10. 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 |
|
| |
March 31 |
|
| ($ millions, except as noted) |
2014 |
|
2013 |
|
| Combined Canadian federal and provincial statutory income tax rate |
29.0 |
% |
29.0 |
% |
| Statutory income tax rate applied to earnings before income taxes, discontinued operations and extraordinary item |
56 |
|
51 |
|
| Difference in Canadian provincial statutory rates applicable to subsidiaries in different Canadian jurisdictions |
(5 |
) |
(6 |
) |
| Difference between Canadian statutory rate and rates applicable to foreign subsidiaries |
(2 |
) |
(2 |
) |
| Items capitalized for accounting purposes but expensed for income tax purposes |
(13 |
) |
(16 |
) |
| Difference between capital cost allowance and amounts claimed for accounting purposes |
1 |
|
(2 |
) |
| Non-deductible expenses |
1 |
|
1 |
|
| Impacts associated with Part VI.1 tax |
- |
|
2 |
|
| Difference between employee future benefits paid and amounts expensed for accounting purposes |
2 |
|
1 |
|
| Other |
(1 |
) |
1 |
|
| Income tax expense |
39 |
|
30 |
|
| Effective income tax rate |
20.2 |
% |
17.1 |
% |
As at March 31, 2014, the Corporation had non-capital and capital loss carryforwards of approximately $113 million (December 31, 2013 - $133 million), of which $12 million (December 31, 2013 - $12 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2034.
11. SALE OF GRIFFITH
In March 2014 Griffith was sold for proceeds of approximately $105 million (US$95 million). The assets and liabilities of Griffith were classified as held for sale on the consolidated balance sheet as at December 31, 2013 and the results of operations have been presented as discontinued operations on the consolidated statements of earnings for the three months ended March 31, 2014.
The table below details the results of discontinued operations.
| |
Quarter Ended |
|
| |
March 31 |
|
| ($ millions) |
2014 |
|
| Revenue |
95 |
|
| |
|
|
| Earnings from discontinued operations before income taxes |
8 |
|
| Income tax expense |
(3 |
) |
| Earnings from discontinued operations, net of tax |
5 |
|
12. 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 ($22 million after tax) was recognized in the first quarter of 2013.
13. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS was as follows:
| Quarter ended March 31, 2014 |
| |
|
|
|
|
|
|
|
|
|
| |
Net Earnings to Common Shareholders |
|
EPS |
| |
Continuing
Operations
($ millions) |
Discontinued
Operations
($ millions) |
Extraordinary
Item
($ millions) |
Total
($ millions) |
Weighted
Average
Number of
Shares
(millions) |
Continuing
Operations |
Discontinued
Operations |
Extraordinary
Item |
Total |
| Basic EPS |
138 |
5 |
- |
143 |
213.6 |
$ 0.65 |
$ 0.02 |
$ - |
$ 0.67 |
| Effect of potential dilutive securities: |
|
|
|
|
|
|
|
|
|
| |
Stock Options |
- |
- |
- |
- |
0.4 |
|
|
|
|
| |
Preference Shares |
2 |
- |
- |
2 |
6.9 |
|
|
|
|
| Diluted EPS |
140 |
5 |
- |
145 |
220.9 |
$ 0.64 |
$ 0.02 |
$ - |
$ 0.66 |
| |
| |
| |
| Quarter ended March 31, 2013 |
| |
|
|
|
|
|
|
|
|
|
| |
Net Earnings to Common Shareholders |
|
EPS |
| |
Continuing
Operations
($ millions) |
Discontinued
Operations
($ millions) |
Extraordinary
Item
($ millions) |
Total
($ millions) |
Weighted
Average
Number of
Shares
(millions) |
Continuing
Operations |
Discontinued
Operations |
Extraordinary
Item |
Total |
| Basic EPS |
129 |
- |
22 |
151 |
192.0 |
$ 0.67 |
$ - |
$ 0.12 |
$ 0.79 |
| Effect of potential dilutive securities: |
|
|
|
|
|
|
|
|
|
| |
Stock Options |
- |
- |
- |
- |
0.8 |
|
|
|
|
| |
Preference Shares |
4 |
- |
- |
4 |
10.0 |
|
|
|
|
| Diluted EPS |
133 |
- |
22 |
155 |
202.8 |
$ 0.66 |
$ - |
$ 0.10 |
$ 0.76 |
Following the satisfaction of all conditions precedent to the closing of the acquisition of UNS Energy, at the option of holders and provided that payment of the final installment has been made, each Debenture will be convertible into common shares of Fortis at any time after the Final Installment Date but prior to maturity or redemption by the Corporation as a conversion price of $30.72 per common share, being a conversion rate of 32.5521 common shares per $1,000 principal amount of Debentures (Note 4). Accordingly, a total of approximately 58.6 million common shares could be issued and outstanding, which would have an impact on basic EPS. Alternatively, if holders do not opt to convert the Debentures into common shares, the Debentures would have an impact on diluted EPS.
14. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| |
REGULATED UTILITIES |
NON-REGULATED |
|
|
|
|
| |
Gas |
Gas &
Electric |
Electric |
|
|
|
|
|
|
|
Quarter Ended
March 31, 2014
($ millions) |
FortisBC
Energy
Cana-
dian |
Central
Hudson
US |
Fortis
Alberta |
FortisBC
Electric |
New-
found-
land
Power |
Other
Cana-
dian |
Total
Elec-
tric
Cana-
dian |
Elec-
tric
Carib-
bean |
Fortis
Generation |
Non-
Utility |
Corporate
and
Other |
|
Inter-
segment
eliminations |
|
Total |
| Revenue |
513 |
272 |
126 |
95 |
209 |
103 |
533 |
74 |
11 |
54 |
7 |
|
(9 |
) |
1,455 |
| Energy supply costs |
251 |
137 |
- |
27 |
149 |
69 |
245 |
45 |
1 |
- |
- |
|
- |
|
679 |
| Operating expenses |
71 |
89 |
43 |
22 |
25 |
13 |
103 |
9 |
2 |
42 |
5 |
|
(2 |
) |
319 |
| Depreciation and amortization |
46 |
11 |
41 |
14 |
13 |
7 |
75 |
9 |
1 |
6 |
- |
|
- |
|
148 |
| Operating income |
145 |
35 |
42 |
32 |
22 |
14 |
110 |
11 |
7 |
6 |
2 |
|
(7 |
) |
309 |
| Other income (expenses), net |
1 |
2 |
2 |
- |
- |
- |
2 |
- |
- |
- |
2 |
|
- |
|
7 |
| Finance charges |
35 |
9 |
19 |
10 |
9 |
5 |
43 |
4 |
- |
6 |
33 |
|
(7 |
) |
123 |
| Income tax expense (recovery) |
32 |
10 |
- |
4 |
3 |
2 |
9 |
- |
1 |
- |
(13 |
) |
- |
|
39 |
| Net earnings (loss) from continuing operations |
79 |
18 |
25 |
18 |
10 |
7 |
60 |
7 |
6 |
- |
(16 |
) |
- |
|
154 |
| Earnings from discontinued operations, net of tax |
- |
- |
- |
- |
- |
- |
- |
- |
- |
5 |
- |
|
- |
|
5 |
| Net earnings (loss) |
79 |
18 |
25 |
18 |
10 |
7 |
60 |
7 |
6 |
5 |
(16 |
) |
- |
|
159 |
| Non-controlling interests |
- |
- |
- |
- |
- |
- |
- |
2 |
- |
- |
- |
|
- |
|
2 |
| Preference share dividends |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
14 |
|
- |
|
14 |
| Net earnings (loss) attributable to common equity shareholders |
79 |
18 |
25 |
18 |
10 |
7 |
60 |
5 |
6 |
5 |
(30 |
) |
- |
|
143 |
| Goodwill |
913 |
499 |
227 |
235 |
- |
67 |
529 |
156 |
- |
- |
- |
|
- |
|
2,097 |
| Identifiable assets |
4,631 |
1,902 |
3,084 |
1,776 |
1,422 |
694 |
6,976 |
724 |
909 |
675 |
1,290 |
|
(614 |
) |
16,493 |
| Total assets |
5,544 |
2,401 |
3,311 |
2,011 |
1,422 |
761 |
7,505 |
880 |
909 |
675 |
1,290 |
|
(614 |
) |
18,590 |
| Gross capital expenditures |
51 |
21 |
79 |
15 |
18 |
7 |
119 |
13 |
24 |
9 |
- |
|
- |
|
237 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quarter Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| March 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenue |
492 |
- |
118 |
88 |
197 |
96 |
499 |
66 |
5 |
53 |
6 |
|
(8 |
) |
1,113 |
| Energy supply costs |
232 |
- |
- |
25 |
145 |
62 |
232 |
41 |
- |
- |
- |
|
- |
|
505 |
| Operating expenses |
72 |
- |
40 |
20 |
23 |
13 |
96 |
8 |
2 |
42 |
3 |
|
(2 |
) |
221 |
| Depreciation and amortization |
46 |
- |
36 |
13 |
12 |
7 |
68 |
8 |
1 |
5 |
1 |
|
- |
|
129 |
| Operating income |
142 |
- |
42 |
30 |
17 |
14 |
103 |
9 |
2 |
6 |
2 |
|
(6 |
) |
258 |
| Other income (expenses), net |
1 |
- |
2 |
- |
1 |
- |
3 |
- |
- |
- |
2 |
|
- |
|
6 |
| Finance charges |
35 |
- |
17 |
9 |
9 |
5 |
40 |
4 |
- |
6 |
10 |
|
(6 |
) |
89 |
| Income tax expense (recovery) |
23 |
- |
1 |
3 |
2 |
3 |
9 |
- |
- |
- |
(2 |
) |
- |
|
30 |
| Net earnings (loss) from continuing operations |
85 |
- |
26 |
18 |
7 |
6 |
57 |
5 |
2 |
- |
(4 |
) |
- |
|
145 |
| Extraordinary gain, net of tax |
- |
- |
- |
- |
- |
- |
- |
- |
22 |
- |
- |
|
- |
|
22 |
| Net earnings (loss) |
85 |
- |
26 |
18 |
7 |
6 |
57 |
5 |
24 |
- |
(4 |
) |
- |
|
167 |
| Non-controlling interests |
- |
- |
- |
- |
- |
- |
- |
2 |
- |
- |
- |
|
- |
|
2 |
| Preference share dividends |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
14 |
|
- |
|
14 |
| Net earnings (loss) attributable to common equity shareholders |
85 |
- |
26 |
18 |
7 |
6 |
57 |
3 |
24 |
- |
(18 |
) |
- |
|
151 |
| Goodwill |
913 |
- |
227 |
235 |
- |
67 |
529 |
143 |
- |
- |
- |
|
- |
|
1,585 |
| Identifiable assets |
4,608 |
- |
2,806 |
1,758 |
1,419 |
709 |
6,692 |
652 |
780 |
678 |
620 |
|
(460 |
) |
13,570 |
| Total assets |
5,521 |
- |
3,033 |
1,993 |
1,419 |
776 |
7,221 |
795 |
780 |
678 |
620 |
|
(460 |
) |
15,155 |
| Gross capital expenditures |
41 |
- |
95 |
17 |
15 |
13 |
140 |
11 |
48 |
13 |
- |
|
- |
|
253 |
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 primarily related to: (i) electricity sales from Newfoundland Power to Non-Utility; and (ii) finance charges on related party borrowings. The significant related party inter-segment transactions for the three months ended March 31, 2014 and 2013 were as follows:
| Significant Related Party Inter-Segment Transactions |
Quarter Ended |
| |
March 31 |
| ($ millions) |
2014 |
2013 |
| Sales from Newfoundland Power to Non-Utility |
2 |
2 |
| Inter-segment finance charges on lending from: |
|
|
| |
Corporate to Regulated Electric Utilities - Caribbean |
1 |
1 |
| |
Corporate to Non-Utility |
5 |
5 |
| |
|
|
| The significant related party inter-segment asset balances were as follows: |
| |
| |
As at March 31 |
| ($ millions) |
2014 |
2013 |
| Inter-segment lending from: |
|
|
| |
Fortis Generation to Other Canadian Electric Utilities |
20 |
20 |
| |
Corporate to Regulated Gas Utilities - Canadian |
18 |
- |
| |
Corporate to Regulated Electric Utilities - Canadian |
86 |
- |
| |
Corporate to Regulated Electric Utilities - Caribbean |
100 |
86 |
| |
Corporate to Fortis Generation |
- |
6 |
| |
Corporate to Non-Utility |
378 |
319 |
| Other inter-segment assets |
12 |
29 |
| Total inter-segment eliminations |
614 |
460 |
15. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| |
Quarter Ended |
|
| |
March 31 |
|
| ($ millions) |
2014 |
|
2013 |
|
| Change in non-cash operating working capital: |
|
|
|
|
| Accounts receivable |
(145 |
) |
(79 |
) |
| Prepaid expenses |
2 |
|
3 |
|
| Regulatory assets - current portion |
(30 |
) |
34 |
|
| Inventories |
70 |
|
55 |
|
| Accounts payable and other current liabilities |
53 |
|
(30 |
) |
| Regulatory liabilities - current portion |
(5 |
) |
35 |
|
| |
(55 |
) |
18 |
|
| |
|
|
|
|
| Non-cash investing and financing activities: |
|
|
|
|
| Common share dividends reinvested |
22 |
|
19 |
|
| Additions to utility capital assets, non-utility capital assets and intangible assets included in current liabilities |
79 |
|
70 |
|
| Contributions in aid of construction included in current assets |
9 |
|
20 |
|
| Exercise of stock options into common shares |
1 |
|
1 |
|
16. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation generally limits the use of derivative instruments to those that qualify as accounting or economic hedges. As at March 31, 2014, the Corporation's derivative instruments primarily consisted of electricity swap contracts, gas swap and option contracts, and gas purchase contract premiums. Electricity swap contracts are held by Central Hudson. Gas swap and option contracts, and gas purchase contract premiums are held by the FortisBC Energy companies.
Volume of Derivative Activity
As at March 31, 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 contracts (gigawatt hours) |
1,068 |
1,095 |
659 |
219 |
| Gas swap and option contracts (petajoules) |
3 |
- |
- |
- |
| Gas purchase contract premiums (petajoules) |
76 |
14 |
- |
- |
Presentation of Derivative Instruments in the Consolidated Financial Statements
On the Corporation's consolidated balance sheet, derivative instruments are presented on a net basis by counterparty, where the right of offset exists.
The Corporation's outstanding derivative balances were as follows:
| |
As at |
|
| |
March 31, |
|
December 31, |
|
| ($ millions) |
2014 |
|
2013 |
|
| Gross derivative asset (1) |
23 |
|
10 |
|
| Gross derivative liability (1) |
(11 |
) |
(15 |
) |
| |
12 |
|
(5 |
) |
| Netting (2) |
- |
|
- |
|
| Cash collateral |
- |
|
- |
|
| Total derivative balance (3) |
12 |
|
(5 |
) |
| |
|
| (1) |
Refer to Note 17 for a discussion of the valuation techniques used to calculate the fair value of the derivative instruments. |
| (2) |
Positions, by counterparty, are netted where the intent and legal right to offset exists. |
| (3) |
Unrealized losses of $11 million on commodity risk-related derivative instruments were recognized in current regulatory assets as at March 31, 2014 (December 31, 2013 - $15 million) and unrealized gains of $23 million (December 31, 2013 - $10 million) were recognized in current and long-term regulatory liabilities. These unrealized losses and gains would otherwise be recognized in earnings. |
Cash flows associated with the settlement of all derivative instruments are included in operating cash flows on the Corporation's consolidated statements of cash flows.
17. FAIR VALUE MEASUREMENTS
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 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 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 details the estimated fair value measurements of the Corporation's financial instruments, all of which were measured using Level 2 pricing inputs, except for other investments, certain long-term debt and derivative instruments, as noted.
| |
As at |
|
| Asset (Liability) |
March 31, 2014 |
|
December 31, 2013 |
|
($ millions) |
Carrying
Value |
|
Estimated
Fair Value |
|
Carrying
Value |
|
Estimated
Fair Value |
|
| Long-term other asset - Belize Electricity (1) |
112 |
|
n/a(2) |
|
108 |
|
n/a (2) |
|
| Other investments (1) (3) |
6 |
|
6 |
|
6 |
|
6 |
|
| Long-term debt, including current portion (4) |
(7,158 |
) |
(8,329 |
) |
(7,204 |
) |
(8,084 |
) |
| Waneta Expansion Limited Partnership ("Waneta Partnership") promissory note (5) |
(50 |
) |
(52 |
) |
(50 |
) |
(50 |
) |
| Electricity swap contracts (6) |
23 |
|
23 |
|
10 |
|
10 |
|
| Natural gas derivatives: (7) |
|
|
|
|
|
|
|
|
| |
Gas swap and option contracts |
(6 |
) |
(6 |
) |
(13 |
) |
(13 |
) |
| |
Gas purchase contract premiums |
(5 |
) |
(5 |
) |
(2 |
) |
(2 |
) |
| |
|
| (1) |
Included in long-term other assets on the consolidated balance sheet |
| (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 18 and 20). |
| (3) |
Other investments were valued using Level 1 inputs. |
| (4) |
The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $175 million (December 31, 2013 - $313 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs. |
| (5) |
Included in long-term other liabilities on the consolidated balance sheet |
| (6) |
The fair value of the electricity swap contracts is recorded in accounts receivable and other long-term assets. The fair value of electricity swap contracts was determined using Level 3 inputs. |
| (7) |
The fair value of the natural gas derivatives is recorded in accounts payable and other current liabilities. |
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 electricity swap contracts are used by Central Hudson to minimize commodity price volatility for electricity purchases by fixing the effective purchase price of electricity. The fair value of the electricity swap contracts was 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 fair values of the electricity swap contracts and natural gas 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. As at March 31, 2014, none of the electricity swap contracts and natural gas derivatives were designated as hedges of electricity and natural gas supply contracts. 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.
18. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
| Credit risk |
Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument. |
| |
|
| Liquidity risk |
Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments. |
| |
|
| Market risk |
Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk. |
Credit Risk
For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2014, FortisAlberta's gross credit risk exposure was approximately $114 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $2 million by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.
The FortisBC Energy companies may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. The following table summarizes the FortisBC Energy companies net credit risk exposure to their counterparties, as well as credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as it relates to their natural gas swaps and options.
| |
As at |
| |
March 31, |
December 31, |
| ($ millions, except as noted) |
2014 |
2013 |
| Gross credit exposure before credit collateral (1) |
6 |
13 |
| Credit collateral |
- |
- |
| Net credit exposure (2) |
6 |
13 |
| |
|
|
| Number of counterparties > 10% (#) |
2 |
2 |
| Net exposure to counterparties > 10% |
5 |
11 |
| |
|
| (1) |
Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported do not include adjustments for time value or liquidity. |
| (2) |
Net credit exposure is the gross credit exposure collateral minus credit collateral (cash deposits and letters of credit). |
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 March 31, 2014, the Corporation had a long-term other asset of $112 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 17 and 20).
Additionally, as at March 31, 2014, Belize Electricity owed Belize Electric Company Limited ("BECOL") approximately US$2 million for energy purchases, of which less than US$1 million was overdue (December 31, 2013 - US $4 million, of which less than US $1 million was overdue). In accordance with long-standing agreements, the GOB guarantees the payment of Belize Electricity's obligations to BECOL.
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 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. Over the next five years, average annual consolidated long-term debt maturities and repayments are expected to be approximately $310 million. 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 March 31, 2014, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.7 billion, of which $2.4 billion was unused, including $824 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 20% of these facilities. Approximately $2.6 billion of the total credit facilities are committed facilities with maturities ranging from 2014 through 2019.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| |
|
|
|
|
|
|
As at |
|
($ millions) |
Regulated
Utilities |
|
Non-Regulated |
|
Corporate
and Other |
|
March 31,
2014 |
|
December 31,
2013 |
|
| Total credit facilities |
1,555 |
|
13 |
|
1,140 |
|
2,708 |
|
2,695 |
|
| Credit facilities utilized: |
|
|
|
|
|
|
|
|
|
|
| |
Short-term borrowings (1) |
(63 |
) |
(1 |
) |
- |
|
(64 |
) |
(160 |
) |
| |
Long-term debt (2) |
- |
|
- |
|
(175 |
) |
(175 |
) |
(313 |
) |
| Letters of credit outstanding |
(67 |
) |
- |
|
(1 |
) |
(68 |
) |
(66 |
) |
| Credit facilities unused |
1,425 |
|
12 |
|
964 |
|
2,401 |
|
2,156 |
|
| |
|
| (1) |
The weighted average interest rate on short-term borrowings was approximately 1.3% as at March 31, 2014 (December 31, 2013 - 1.3%) |
| (2) |
As at March 31, 2014, credit facility borrowings classified as long term included $nil 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 1.2% as at March 31, 2014 (December 31, 2013 - 1.8%). |
As at March 31, 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 February 2014 Maritime Electric's $50 million unsecured revolving credit facility matured and the Company negotiated a new $50 million unsecured committed revolving credit facility, maturing in February 2019.
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 April 2014 FHI extended its $30 million unsecured committed revolving credit facility to mature in May 2015 from May 2014.
For the purpose of bridge financing for the pending acquisition of UNS Energy (Note 1), in March 2014 the Corporation secured an aggregate of $2 billion non-revolving term credit facilities from a syndicate of banks. The non-revolving term credit facilities are comprised 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. The credit facilities table does not include the $2 billion credit facilities.
As a result of closing the Debentures related to the pending acquisition of UNS Energy (Note 1), the Corporation agreed to maintain availability under its committed revolving corporate credit facility of not less than $600 million to cover the principal amount of the first installment of the Debentures in the event of a mandatory redemption (Note 4).
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 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. Similarly, S&P revised its outlook on the Corporation to negative from stable. S&P indicated that an outlook revision to stable would likely occur when the Corporation's Debentures are converted to equity (Note 4).
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 effectively 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 loss or gain on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of Central Hudson, Caribbean Utilities, Fortis Turks and Caicos, BECOL and FortisUS Energy Corporation is the US dollar.
As at March 31, 2014, the Corporation's corporately issued US$1,033 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 March 31, 2014, the Corporation had approximately US$585 million (December 31, 2013 - US$560 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded 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.
Effective June 20, 2011, the Corporation's asset associated with its expropriated investment in Belize Electricity (Notes 17 and 20) 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 $4 million and $2 million during the three months ended March 31, 2014 and 2013, respectively (Note 8).
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 and Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and natural gas (Notes 16 and 17). The risks have been reduced by entering derivative contracts that effectively fix the price of natural gas purchases and electricity purchases, respectively. The natural gas and electricity derivatives 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.
19. COMMITMENTS
There were no 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 statements, except as follows.
Commitments as at March 31, 2014 include Central Hudson's contract to purchase 200 megawatts ("MW") of installed capacity from May 1, 2014 through April 30, 2017 totalling approximately US$63 million. The New York Independent System Operator ("NYISO") has been authorized by FERC to create a new capacity zone in the Lower Hudson Valley to maintain system reliability and attract investments in new and existing generation, which will be implemented in May 2014. The key terms of the contract provide that Central Hudson will pay the settlement price in the NYISO Capacity Spot Market auction for the relevant month of delivery minus US$0.175 per kilowatt-month, times the contract quantity of the product delivered during the month.
On May 6, 2014, the BCUC approved FortisBC Electric's new power purchase agreement ("PPA") 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.
To finance a portion of the pending 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 (Note 4).
In March 2014 Fortis priced a private placement to US-based institutional investors of US$500 million in senior unsecured notes. The notes will be 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%. The weighted average term to maturity is approximately 11 years and the weighted average coupon rate is 3.85%. Subject to the satisfaction of customary closing conditions, US$213 million of notes will be issued on June 30, 2014 and US$287 million of notes will be issued on September 15, 2014.
Net proceeds from the sale of the notes will be used to refinance existing indebtedness, including the US$150 million 5.74% senior unsecured notes of Fortis maturing on October 30, 2014 and $125 million 5.56% unsecured debentures of a subsidiary maturing on September 15, 2014, and for general corporate purposes, including repayment of US-dollar drawings on the Corporation's committed credit facility.
20. 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 is pending. Any decision of the Belize Court of Appeal may be appealed to the Caribbean Court of Justice, the highest court of appeal available for judicial matters in Belize.
Fortis believes it has a strong, well-positioned case before the Belize Courts 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 otherwise to be paid to Fortis under the legislation expropriating Belize Electricity could be lower than the book value of the Corporation's expropriated investment in Belize Electricity. The book value was $112 million, including foreign exchange impacts, as at March 31, 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 $112 million long-term other asset is not deemed impaired as at March 31, 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.
21. CONTINGENCIES
The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position 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 is subject to court approval. In February 2014 the Supreme Court of the State of New York, County of New York, issued a Consent Order preliminarily certifying the matter as a class action and providing directions leading to a Settlement Hearing to be held in June 2014.
Following the announcement of the proposed 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 proposed acquisition. The complaints generally allege that the directors of UNS Energy breached their fiduciary duties in connection with the proposed transaction and that UNS Energy, Fortis, FortisUS Inc., and Color Acquisition Sub Inc. aided and abetted that breach. On March 13, 2014, two of the four complaints filed in the Superior Court were dismissed by the plaintiffs. On March 18, 2014, 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. On April 15, 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.
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. The Government of British Columbia has disclosed that its claim includes approximately $15 million in damages as well as pre-judgment interest, but that it has not fully quantified its damages. FortisBC Electric and its insurers continue to defend the claim by the Government of British Columbia. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
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 March 31, 2014, an obligation of US$46 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 (Note 3).
Eltings Corners
Central Hudson owns and operates a maintenance and warehouse facility. In the course of Central Hudson's hazardous waste permit renewal process for this facility, sediment contamination was discovered within the wetland area across the street from the main property. Based on the investigation work completed by Central Hudson, the DEC and Central Hudson agreed in late 2013 that no additional investigation efforts are necessary. As requested by the DEC, Central Hudson submitted a draft Corrective Measures Study scoping document for review by the DEC. The extent of the contamination has been established and approximately US$3 million has been accrued in the consolidated financial statements.
Asbestos Litigation
Prior to the acquisition of CH Energy Group, various asbestos lawsuits had been brought against Central Hudson. While a total of 3,343 asbestos cases have been raised, 1,171 remained pending as at March 31, 2014. Of the cases no longer pending against Central Hudson, 2,017 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.
22. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned electric and gas distribution utility in Canada. Its regulated utilities account for approximately 90% of total assets and serve approximately 2.5 million customers across Canada and in New York State 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 Installment Receipts 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.IR, respectively.
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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.