ST. JOHN'S, NEWFOUNDLAND - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net earnings attributable to common equity shareholders of $151 million, or $0.79 per common share, compared to $121 million, or $0.64 per common share, for the first quarter of 2012.
Earnings for the quarter were favourably impacted by an extraordinary gain of approximately $22 million net of tax, or $0.12 per common share, related to the settlement of all matters, including release from all debt obligations, pertaining to the Government of Newfoundland and Labrador's December 2008 expropriation of non-regulated hydroelectric generating assets and water rights in central Newfoundland, then owned by Exploits River Hydro Partnership ("Exploits Partnership") in which Fortis holds an indirect 51% interest.
"In addition to the settlement of expropriation matters relating to Exploits Partnership, performance for the quarter was driven by the regulated utilities in western Canada, led by FortisAlberta," says Stan Marshall, President and Chief Executive Officer, Fortis Inc.
Canadian Regulated Electric Utilities contributed earnings of $57 million, up $6 million from the first quarter of 2012. FortisAlberta's earnings increased $5 million, due to lower depreciation of $3 million and net transmission revenue of approximately $2 million recognized in the first quarter of 2013 associated with the finalization of 2012 transmission variances. The utility's depreciation rates were reduced, effective January 1, 2012, as a result of the decision related to FortisAlberta's 2012 revenue requirements, the impact of which was not recognized until the second quarter of 2012 when the decision was received. FortisBC Electric's earnings were $2 million higher quarter over quarter, due to growth in energy infrastructure investment, timing of operating expenses, lower-than-expected finance charges and depreciation, and higher capitalized allowance for funds used during construction, partially offset by higher effective income taxes.
FortisBC Electric acquired the City of Kelowna's (the "City's") electrical utility assets for approximately $55 million in March 2013, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.
Canadian Regulated Gas Utilities contributed earnings of $85 million, up $3 million from the first quarter of 2012. The increase in earnings was mainly due to growth in energy infrastructure investment and increased gas transportation volumes to industrial customers, partially offset by lower-than-expected customer additions and higher effective income taxes.
Fortis paid a dividend of 31 cents per common share on March 1, 2013, up from 30 cents for the fourth quarter of 2012. The 3.3% increase in the quarterly dividend translates into an annualized dividend of $1.24 and extends the Corporation's record of annual common share dividend increases to 40 consecutive years, the longest record of any public corporation in Canada.
FortisAlberta received a decision from its regulator in March 2013 approving an interim increase in customer distribution rates, effective January 1, 2013, including interim approval of 60% of the revenue requirement associated with certain capital expenditures in 2013 not otherwise recovered under performance-based rates. Final decisions on the utility's rates are expected in the second half of 2013.
In April 2013 Newfoundland Power received a cost of capital decision whereby the utility's allowed rate of return on common shareholders' equity ("ROE") and common equity component of capital structure will remain at 8.8% and 45%, respectively, for 2013 through 2015.
Final allowed ROEs and capital structure for 2013 remain to be determined for FortisBC and FortisAlberta. A decision associated with the first phase of a Generic Cost of Capital ("GCOC") Proceeding in British Columbia as it affects FortisBC Energy Inc. is expected mid-2013 and the second phase of the proceeding, which will affect the other FortisBC utilities, commenced in March 2013. The process for the GCOC Proceeding in Alberta is scheduled to commence in the second quarter of 2013.
Caribbean Regulated Electric Utilities contributed $3 million of earnings, consistent with the first quarter of 2012.
Non-Regulated Fortis Generation contributed $24 million of earnings compared to $5 million for the first quarter of 2012. Excluding the $22 million after-tax extraordinary gain on the settlement of expropriation matters, as noted above, earnings decreased $3 million, mainly related to lower production in Belize due to lower rainfall.
Fortis Properties contributed earnings of less than $0.5 million for the first quarter of 2013 compared to $1 million for the first quarter of 2012. The decrease was mainly due to lower occupancy levels at the Hospitality Division's operations in central Canada.
Corporate and other expenses were $18 million compared to $21 million for the first quarter of 2012. Corporate and other expenses for the first quarter of 2013 were reduced by $2 million related to foreign exchange, while corporate and other expenses for the same quarter last year were increased by $1.5 million associated with foreign exchange. CH Energy Group, Inc. ("CH Energy Group") acquisition-related expenses were approximately $0.5 million after tax for the first quarter of 2013 compared to $4 million after tax for the same quarter last year. Excluding the above-noted acquisition-related expenses and foreign exchange impacts, corporate and other expenses increased $4 million quarter over quarter, mainly as a result of higher preference share dividends, partially offset by lower finance charges.
Consolidated capital expenditures, before customer contributions, were approximately $250 million for the first quarter of 2013. 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 $483 million in total has been spent on the Waneta Expansion since construction began in late 2010.
The Corporation's capital program is expected to total $1.3 billion in 2013. Over the five years 2013 through 2017, the Corporation's capital program, including expenditures at Central Hudson Gas & Electric Corporation ("Central Hudson"), is expected to total approximately $6 billion.
Cash flow from operating activities was $280 million for the quarter compared to $328 million for the first quarter of 2012. The decrease was largely due to changes in working capital quarter over quarter.
Fortis has consolidated credit facilities of $2.4 billion, of which $2.0 billion was unused as at March 31, 2013, including $910 million available for borrowing under its corporate credit facility.
The Corporation's debt credit ratings of A- and A(low) were affirmed by Standard & Poor's and DBRS, respectively, in February 2013.
Fortis announced in February 2012 that it had entered into an agreement to acquire CH Energy Group, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. Central Hudson, the main business of CH Energy Group, serves 375,000 electric and gas customers in New York State's Mid-Hudson River Valley. Approval of the acquisition by the New York State Public Service Commission ("PSC") is the last significant regulatory matter required to close the transaction. A Settlement Agreement among Fortis, CH Energy Group, PSC staff, registered interveners and other parties was filed with the PSC in January 2013. A Recommended Decision issued on May 3, 2013 by administrative law judges in connection with the acquisition asserts that without modification of the terms of the Settlement Agreement, the benefits of the acquisition are outweighed by perceived detriments remaining after mitigation. The Recommended Decision is an advisory opinion that will be considered by the PSC in determining whether to approve the acquisition. While no assurance regarding a closing of the transaction can be given until an order is issued by the PSC, a final decision by the PSC and subsequent closing of the transaction is expected in June 2013. Based on the terms of the current Settlement Agreement, the acquisition is expected to be accretive to earnings per common share of Fortis within the first full year of ownership, excluding acquisition-related expenses.
"We look forward to welcoming the employees of CH Energy Group to the Fortis Group. The addition of this well-run U.S. utility and its proven track record for providing customers with quality service will further enhance the positioning of Fortis as a leader in the North American utility industry," concludes Marshall.
| Interim Management Discussion and Analysis |
| For the three months ended March 31, 2013 |
| Dated May 7, 2013 |
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, 2013 and the MD&A and audited consolidated financial statements for the year ended December 31, 2012 included in the Corporation's 2012 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 Management Discussion and Analysis ("MD&A") within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation.
The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to the Corporation's management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the Corporation's forecasted gross consolidated capital expenditures for 2013 and total capital spending over the five-year period 2013 through 2017, including expenditures at Central Hudson Gas & Electric Corporation; the expectation that capital investment over the above-noted five-year period will allow utility rate base and hydroelectric investment to increase at a combined compound annual growth rate of approximately 6%; the expected nature, timing and capital cost related to the construction of the Waneta Expansion hydroelectric generating facility ("Waneta Expansion"); 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 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 expected consolidated long-term debt maturities and repayments on average annually over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2013; the expected timing of filing of regulatory applications and of receipt of regulatory decisions; the expected timing of the closing of the acquisition of CH Energy Group, Inc. ("CH Energy Group") by Fortis and the expectation that, based on the terms of the current Settlement Agreement, the acquisition will be accretive to earnings per common share of Fortis within the first full year of ownership, excluding acquisition-related expenses; the expectation that the Corporation's capital expenditure program will support continuing growth in earnings and dividends; and the Corporation's expected regulated midyear rate base in 2013 upon closing of the CH Energy Group acquisition.
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 continues to recover its cost of service and earn its allowed rate of return on common shareholders' equity ("ROE") under performance-based rate-setting, which commenced for a five-year term effective January 1, 2013; the receipt of regulatory approval of the acquisition of CH Energy Group from the New York State Public Service Commission; the closing of the acquisition of CH Energy Group before the expiry of the Subscription Receipts; 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; 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 commodity cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas commodity prices and fuel 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 accounting principles generally accepted in the United States beyond 2014 or the adoption of International Financial Reporting Standards after 2014 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, 2012 and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities. Key risk factors for 2013 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 each of the Corporation's regulated utilities in western Canada; risks related to the ability to close the acquisition of CH Energy Group, the timing of such closing and the realization of the 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 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 distribution utility in Canada, serving more than two million gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, in Canada, Belize and Upstate New York, and hotels and commercial office and retail space in Canada. Year-to-date March 31, 2013, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,152 megawatts ("MW") and its gas distribution system met a peak day demand of 1,113 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, 2013 and to the "Corporate Overview" section of the 2012 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 rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA; (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 forecasted 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 CH Energy Group, Inc.: On May 3, 2013 a Recommended Decision was issued by administrative law judges in connection with the Settlement Agreement filed by Fortis, CH Energy Group, Inc. ("CH Energy Group"), New York State Public Service Commission ("PSC") staff, registered interveners and other parties in January 2013 requesting approval of the acquisition of CH Energy by Fortis. For further information on the pending acquisition and Recommended Decision, refer to the "Business Risk Management" section of this MD&A.
Settlement of Expropriation Matters - Exploits River Hydro Partnership: Effective March 2013 the Corporation and the Government of Newfoundland and Labrador ("Government") 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 Exploits River Hydro Partnership ("Exploits Partnership") in which Fortis holds an indirect 51% interest. As a result of the settlement of expropriation matters, an extraordinary after-tax gain of approximately $22 million was recognized in the first quarter of 2013.
Acquisition of the Electrical Utility Assets from the City of Kelowna: FortisBC Electric acquired the City of Kelowna's (the "City's") electrical utility assets for approximately $55 million in March 2013, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.
Receipt of Regulatory Decisions: FortisAlberta received a decision from its regulator in March 2013 approving an interim increase in customer distribution rates, effective January 1, 2013.
In April 2013 Newfoundland Power received a decision on cost of capital. The utility's allowed ROE and common equity component of capital structure have been set for 2013 through 2015 and remain unchanged from 2012.
For a further discussion on the nature of the above regulatory decisions, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the first quarters ended March 31, 2013 and March 31, 2012 are provided in the following table.
| Consolidated Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions, except for common share data) |
2013 |
2012 |
|
Variance |
|
| Revenue |
1,113 |
1,149 |
|
(36 |
) |
| Energy Supply Costs |
505 |
566 |
|
(61 |
) |
| Operating Expenses |
221 |
214 |
|
7 |
|
| Depreciation and Amortization |
129 |
119 |
|
10 |
|
| Other Income (Expenses), Net |
6 |
(3 |
) |
9 |
|
| Finance Charges |
89 |
91 |
|
(2 |
) |
| Income Taxes |
30 |
23 |
|
7 |
|
| Earnings Before Extraordinary Item |
145 |
133 |
|
12 |
|
| Extraordinary Gain, Net of Tax |
22 |
- |
|
22 |
|
| Net Earnings |
167 |
133 |
|
34 |
|
| Net Earnings Attributable to: |
|
|
|
|
|
| |
Non-Controlling Interests |
2 |
1 |
|
1 |
|
| |
Preference Equity Shareholders |
14 |
11 |
|
3 |
|
| |
Common Equity Shareholders |
151 |
121 |
|
30 |
|
| Net Earnings |
167 |
133 |
|
34 |
|
| Earnings per Common Share Before Extraordinary Item |
|
|
|
|
|
| |
Basic ($) |
0.67 |
0.64 |
|
0.03 |
|
| |
Diluted ($) |
0.66 |
0.62 |
|
0.04 |
|
| Earnings per Common Share |
|
|
|
|
|
| |
Basic ($) |
0.79 |
0.64 |
|
0.15 |
|
| |
Diluted ($) |
0.76 |
0.62 |
|
0.14 |
|
| Weighted Average Number of Common Shares |
|
|
|
|
|
| |
Outstanding (# millions) |
192.0 |
189.0 |
|
3.0 |
|
| Cash Flow from Operating Activities |
280 |
328 |
|
(48 |
) |
Factors Contributing to Revenue Variance
Unfavourable
- Lower commodity cost of natural gas charged to customers
- Lower average gas consumption by residential and commercial customers, due to warmer temperatures
- Decreased non-regulated hydroelectric production in Belize, due to lower rainfall
- Decreased electricity sales at FortisBC Electric, due to warmer temperatures
Favourable
- An increase in gas delivery rates and the base component of electricity rates at most of the regulated utilities, consistent with rate decisions, reflecting ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers
- Higher average gas transportation volumes to industrial customers
- Growth in the number of customers, driven by FortisAlberta
- Increased electricity sales at Newfoundland Power, Maritime Electric and Fortis Turks and Caicos
- Net transmission revenue of approximately $2 million recognized at FortisAlberta in the first quarter of 2013, associated with the finalization of 2012 net transmission volume variances
Factors Contributing to Energy Supply Costs Variance
Favourable
- Lower commodity cost of natural gas
- Lower average gas consumption by residential and commercial customers, which reduced natural gas purchases
Unfavourable
- Increased electricity sales at Newfoundland Power, Maritime Electric and Fortis Turks and Caicos, which increased fuel and power purchases
- Increased costs at Maritime Electric associated with energy supply costs being expensed in the first quarter of 2013 related to the New Brunswick Power Point Lepreau nuclear generating station ("Point Lepreau"), which returned to service in the fourth quarter of 2012
Factors Contributing to Operating Expenses Variance
Unfavourable
- General inflationary and employee-related cost increases at most of the Corporation's regulated utilities
- Higher operating expenses at Newfoundland Power, mainly due to costs incurred in the first quarter of 2013 associated with restoration efforts following the loss of energy supply from Newfoundland and Labrador Hydro ("Newfoundland Hydro") in January 2013, increased costs associated with customer energy conservation programs, and the impact of regulator-approved cost recovery deferrals in 2012, which reduced operating expenses in the first quarter of last year
- Higher contracting and information technology support costs at the FortisBC Energy companies
Favourable
- Timing of expenditures at FortisBC Electric
Factors Contributing to Depreciation and Amortization Expense Variance
Unfavourable
- Continued investment in energy infrastructure
Favourable
- Lower depreciation rates at FortisAlberta, effective January 1, 2012, as a result of the 2012 distribution revenue requirements decision received in April 2012. The cumulative impact of the overall decrease in depreciation rates was recognized in the second quarter of 2012, when the decision was received, of which approximately $3 million of decreased depreciation expense related to the first quarter of 2012.
Factors Contributing to Other Income (Expenses), Net Variance
Favourable
- Approximately $0.5 million of costs incurred during the first quarter of 2013, compared to $4 million of costs incurred during the first quarter of 2012, related to the pending acquisition of CH Energy Group
- A foreign exchange gain of approximately $2 million recognized in the first quarter of 2013, compared to a foreign exchange loss of $1.5 million recognized in the first quarter of 2012, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity
Factor Contributing to Finance Charges Variance
Favourable
- Higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion hydroelectric generating facility ("Waneta Expansion")
Factors Contributing to Income Taxes Variance
Unfavourable
- Higher earnings before income taxes
- Differences in the deductions for income tax purposes compared to accounting purposes quarter over quarter
Factor Contributing to Extraordinary Gain, Net of Tax Variance
Favourable
- An approximate $25 million ($22 million after-tax) extraordinary gain recognized in the first quarter of 2013 on the settlement of expropriation matters associated with Exploits Partnership
Factors Contributing to Earnings Variance
Favourable
- An approximate $22 million after-tax extraordinary gain recognized in the first quarter of 2013 on the settlement of expropriation matters associated with Exploits Partnership
- Increased earnings at FortisAlberta, due to lower depreciation of $3 million and net transmission revenue of approximately $2 million recognized in the first quarter of 2013 associated with the finalization of 2012 net transmission volume variances
- Increased earnings at the FortisBC Energy companies, mainly due to rate base growth and increased transportation volumes to industrial customers, partially offset by lower-than-expected customer additions and higher effective income taxes
- Lower corporate expenses due to: (i) a foreign exchange gain of approximately $2 million recognized in the first quarter of 2013, compared to a foreign exchange loss of $1.5 million recognized in the first quarter of 2012, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity; (ii) approximately $0.5 million of costs incurred during the first quarter of 2013, compared to $4 million of costs incurred during the first quarter of 2012, related to the pending acquisition of CH Energy Group; and (iii) lower finance charges, primarily due to higher capitalized interest associated with financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion. The above items were partially offset by higher preference share dividends and a lower income tax recovery.
- Increased earnings at FortisBC Electric, due to rate base growth, timing of operating expenses, lower-than-expected finance charges and depreciation, and higher capitalized allowance for funds used during construction ("AFUDC"), partially offset by higher effective income taxes
Unfavourable
- Decreased non-regulated hydroelectric production in Belize, due to lower rainfall
- Decreased earnings at Maritime Electric, due to higher energy supply costs, partially offset by higher electricity sales
- Decreased earnings at Fortis Properties, mainly due to lower occupancy levels at the Hospitality Division's operations in central Canada
SEGMENTED RESULTS OF OPERATIONS
| Segmented Net Earnings Attributable to Common Equity Shareholders |
|
| (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
Variance |
|
| Regulated Gas Utilities - Canadian |
|
|
|
|
|
|
| |
FortisBC Energy Companies |
85 |
|
82 |
|
3 |
|
| Regulated Electric Utilities - Canadian |
|
|
|
|
|
|
| |
FortisAlberta |
26 |
|
21 |
|
5 |
|
| |
FortisBC Electric |
18 |
|
16 |
|
2 |
|
| |
Newfoundland Power |
7 |
|
7 |
|
- |
|
| |
Other Canadian Electric Utilities |
6 |
|
7 |
|
(1 |
) |
| |
57 |
|
51 |
|
6 |
|
| Regulated Electric Utilities - Caribbean |
3 |
|
3 |
|
- |
|
| Non-Regulated - Fortis Generation |
24 |
|
5 |
|
19 |
|
| Non-Regulated - Fortis Properties |
- |
|
1 |
|
(1 |
) |
| Corporate and Other |
(18 |
) |
(21 |
) |
3 |
|
| Net Earnings Attributable to Common Equity Shareholders |
151 |
|
121 |
|
30 |
|
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Corporation's regulated utilities, refer to the "Regulatory Highlights" section of this MD&A. A discussion of the financial results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2013 |
2012 |
Variance |
|
| Gas Volumes (petajoules ("PJ")) |
71 |
72 |
(1 |
) |
| Revenue ($ millions) |
492 |
548 |
(56 |
) |
| Earnings ($ millions) |
85 |
82 |
3 |
|
| |
|
| (1) |
Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI") |
Factors Contributing to Gas Volumes Variance
Unfavourable
- Lower average gas consumption by residential and commercial customers, due to warmer temperatures
Favourable
- Higher average gas transportation volumes to industrial customers
As at March 31, 2013, the total number of customers served by the FortisBC Energy companies was approximately 948,000. Net customer additions were 3,000 during the first quarter of 2013 compared to 1,000 during the first quarter of 2012.
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 forecasted 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.
Factors Contributing to Revenue Variance
Unfavourable
- Lower commodity cost of natural gas charged to customers
- Lower average gas consumption by residential and commercial customers
- Lower-than-expected customer additions
Favourable
- An increase in the delivery component of customer rates, effective January 1, 2013, mainly due to ongoing investment in energy infrastructure and forecasted higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in April 2012
- Higher average gas transportation volumes to industrial customers
Factors Contributing to Earnings Variance
Favourable
- Rate base growth, due to continued investment in energy infrastructure
- Higher average gas transportation volumes to industrial customers
Unfavourable
- Lower-than-expected customer additions
- Higher effective income taxes, due to differences in the deductions for income tax purposes compared to accounting purposes quarter over quarter
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2013 |
2012 |
Variance |
| Energy Deliveries (gigawatt hours ("GWh")) |
4,491 |
4,482 |
9 |
| Revenue ($ millions) |
118 |
108 |
10 |
| Earnings ($ millions) |
26 |
21 |
5 |
Factors Contributing to Energy Deliveries Variance
Favourable
- Growth in the number of customers, mainly in the residential sector, with the total number of customers increasing by approximately 10,000 year over year as at March 31, 2013, driven by favourable economic conditions
- Higher average consumption by oil field customers, primarily due to higher drilling activity
- Higher average consumption by residential customers, due to cooler temperatures
Unfavourable
- Lower average consumption by oil and gas customers, mainly due to decreased activity associated with a lower commodity price for natural gas
As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
Factors Contributing to Revenue Variance
Favourable
- An interim increase in customer electricity distribution rates, effective January 1, 2013, associated with the regulator's interim decision received in March 2013 related to FortisAlberta's PBR Compliance Application
- Growth in the number of customers
- Net transmission revenue of approximately $2 million recognized in the first quarter of 2013, associated with the finalization of 2012 net transmission volume variances. As approved by the regulator in April 2012, FortisAlberta assumed the risk of volume variances related to net transmission costs during 2012. The deferral of transmission volume variances, however, was reinstated by the regulator, effective January 1, 2013.
Factors Contributing to Earnings Variance
Favourable
- Lower depreciation rates, effective January 1, 2012, as a result of the 2012 distribution revenue requirements decision received in April 2012. The cumulative impact of the overall decrease in depreciation rates was recognized in the second quarter of 2012, when the decision was received, of which approximately $3 million of decreased depreciation expense related to the first quarter of 2012.
- Net transmission revenue of approximately $2 million recognized in the first quarter of 2013, for the reason discussed above
FORTISBC ELECTRIC (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2013 |
2012 |
Variance |
|
| Electricity Sales (GWh) |
891 |
909 |
(18 |
) |
| Revenue ($ millions) |
88 |
87 |
1 |
|
| Earnings ($ millions) |
18 |
16 |
2 |
|
| |
|
| (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. In March 2013 FortisBC Inc. acquired the City of Kelowna's electrical utility assets for approximately $55 million, previous to which time FortisBC Inc. had operated and maintained the assets under contract since 2000. For further information, refer to the "Significant Items" section of this MD&A. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership. |
Factor Contributing to Electricity Sales Variance
Unfavourable
- Lower average consumption, due to warmer temperatures
Factors Contributing to Revenue Variance
Favourable
- An increase in customer electricity rates, effective January 1, 2013, mainly due to ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in August 2012
Unfavourable
- The 2.0% decrease in electricity sales
- Differences in the amortization to revenue of flow through adjustments owing to customers quarter over quarter
Factors Contributing to Earnings Variance
Favourable
- Rate base growth, due to continued investment in energy infrastructure
- Lower operating expenses due to the timing of expenditures
- Lower-than-expected finance charges and depreciation in the first quarter of 2013
- Higher capitalized AFUDC, as approved by the regulator
Unfavourable
- Higher effective income taxes, due to lower deductions for income tax purposes
NEWFOUNDLAND POWER
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2013 |
2012 |
Variance |
| Electricity Sales (GWh) |
1,942 |
1,914 |
28 |
| Revenue ($ millions) |
197 |
192 |
5 |
| Earnings ($ millions) |
7 |
7 |
- |
Factors Contributing to Electricity Sales Variance
Favourable
- Growth in the number of customers
- Higher average consumption, reflecting the higher concentration of electric-versus-oil heating in new home construction combined with economic growth
Factors Contributing to Revenue Variance
Favourable
- The 1.5% increase in electricity sales
- Increased amortization to revenue of regulatory liabilities and deferrals, as approved by the regulator
Factors Contributing to Earnings Variance
Favourable
Unfavourable
- Increased operating expenses, mainly due to costs incurred in the first quarter of 2013 associated with restoration efforts following the loss of energy supply from Newfoundland Hydro in January 2013, increased costs associated with customer energy conservation programs, and the impact of regulator-approved cost recovery deferrals in 2012, which reduced operating expenses in the first quarter of last year
- Higher depreciation, due to continued investment in energy infrastructure
OTHER CANADIAN ELECTRIC UTILITIES (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2013 |
2012 |
Variance |
|
| Electricity Sales (GWh) |
671 |
645 |
26 |
|
| Revenue ($ millions) |
96 |
91 |
5 |
|
| Earnings ($ millions) |
6 |
7 |
(1 |
) |
| |
|
| (1) |
Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power. |
Factor Contributing to Electricity Sales Variance
Favourable
- Higher average consumption, due to colder temperatures on Prince Edward Island ("PEI") and in Ontario, as well as an increase in the number of customers using electricity for home heating on PEI
Factor Contributing to Revenue Variance
Favourable
- Higher electricity sales, driven by Maritime Electric, combined with an increase in the basic component of customer rates at the utility, effective March 1, 2013
Factors Contributing to Earnings Variance
Unfavourable
- Higher energy supply costs at Maritime Electric, largely associated with energy supply costs being expensed in the first quarter of 2013 related to Point Lepreau, which returned to service in the fourth quarter of 2012
Favourable
- Electricity sales growth at Maritime Electric
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
| |
2013 |
2012 |
Variance |
| Average US:CDN Exchange Rate (2) |
1.01 |
1.00 |
0.01 |
| Electricity Sales (GWh) |
170 |
166 |
4 |
| Revenue ($ millions) |
66 |
63 |
3 |
| Earnings ($ millions) |
3 |
3 |
- |
| |
|
| (1) |
Comprised of Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling interest; three small wholly owned utilities in the Turks and Caicos Islands, comprised of FortisTCI Limited ("FortisTCI"), Atlantic Equipment & Power (Turks and Caicos) Ltd. ("Atlantic") and Turks and Caicos Utilities Limited ("TCU"), acquired in August 2012, (collectively "Fortis Turks and Caicos") |
| |
|
| (2) |
The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. |
Factor Contributing to Electricity Sales Variance
Favourable
- Increased electricity sales at Fortis Turks and Caicos due to electricity sales of 5 GWh at TCU, which was acquired in August 2012, partially offset by lower average consumption by commercial customers at FortisTCI, mainly due to higher fuel costs and resulting energy conservation by customers
Factors Contributing to Revenue Variance
Favourable
- Increased electricity sales at Fortis Turks and Caicos
- An increase in electricity rates for FortisTCI's large hotel customers, effective April 1, 2012
- The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, due to an increase in the cost of fuel
Factors Contributing to Earnings Variance
Favourable
- Decreased operating expenses at Caribbean Utilities, mainly due to lower employee-related costs and maintenance costs
Unfavourable
- Overall higher depreciation expense, due to continued investment in energy infrastructure
NON-REGULATED - FORTIS GENERATION (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2013 |
2012 |
Variance |
|
| Energy Sales (GWh) |
55 |
88 |
(33 |
) |
| Revenue ($ millions) |
5 |
9 |
(4 |
) |
| Earnings ($ millions) |
24 |
5 |
19 |
|
| |
|
| (1) |
Comprised of the financial results of non-regulated generation assets in Belize, Ontario, British Columbia and Upstate New York, with a combined generating capacity of 103 MW, mainly hydroelectric |
Factor Contributing to Energy Sales and Revenue Variances
Unfavourable
- Decreased production in Belize, due to lower rainfall
Factors Contributing Earnings Variance
Favourable
- An approximate $22 million after-tax extraordinary gain on the settlement of expropriation matters associated with Exploits Partnership. For further information, refer to the "Significant Items" section of this MD&A.
Unfavourable
- Decreased production in Belize
NON-REGULATED - FORTIS PROPERTIES (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| |
2013 |
|
2012 |
|
Variance |
|
| Hospitality - Revenue per Available Room ("RevPar") |
$ 66.04 |
|
$ 66.54 |
|
(0.8 |
)% |
| Real Estate - Occupancy Rate (as at) |
91.2 |
% |
92.2 |
% |
(1.1 |
)% |
| Hospitality Revenue ($ millions) |
36 |
|
35 |
|
1 |
|
| Real Estate Revenue ($ millions) |
17 |
|
17 |
|
- |
|
| |
Total Revenue ($ millions) |
53 |
|
52 |
|
1 |
|
| Earnings ($ millions) |
- |
|
1 |
|
(1 |
) |
| |
|
| (1) |
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. |
Factors Contributing to RevPar Variance
Unfavourable
- A 2.6% decrease in occupancy in all regions, with the most significant decrease in central Canada
Favourable
- A 1.8% increase in the average daily room rate, mainly in Atlantic Canada and western Canada
Factor Contributing to Revenue Variance
Favourable
- Increased revenue at the Hospitality Division, mainly due to contribution from the StationPark All Suite Hotel, which was acquired in October 2012, partially offset by lower revenue from other hotel operations in central Canada
Factor Contributing to Earnings Variance
Unfavourable
- Lower performance at the Hospitality Division, primarily due to the impact of decreased occupancy levels at hotel operations in central Canada
CORPORATE AND OTHER (1)
| Financial Highlights (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
Variance |
|
| Revenue |
6 |
|
6 |
|
- |
|
| Operating Expenses |
3 |
|
3 |
|
- |
|
| Depreciation and Amortization |
1 |
|
1 |
|
- |
|
| Other Income (Expenses), Net |
2 |
|
(5 |
) |
7 |
|
| Finance Charges |
10 |
|
11 |
|
(1 |
) |
| Income Tax Recovery |
(2 |
) |
(4 |
) |
2 |
|
| |
(4 |
) |
(10 |
) |
6 |
|
| Preference Share Dividends |
14 |
|
11 |
|
3 |
|
| Net Corporate and Other Expenses |
(18 |
) |
(21 |
) |
3 |
|
| |
|
| (1) |
Includes Fortis net corporate expenses, net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities, and the financial results of FHI's wholly owned subsidiary FortisBC Alternative Energy Services Inc. and FHI's 30% ownership interest in CustomerWorks Limited Partnership. |
Factors Contributing to Net Corporate and Other Expenses Variance
Favourable
- Increased other income, net of other expenses, primarily due to: (i) a foreign exchange gain of approximately $2 million recognized in the first quarter of 2013, compared to a foreign exchange loss of $1.5 million recognized in the first quarter of 2012, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity; and (ii) approximately $0.5 million of costs incurred during the first quarter of 2013, compared to $4 million of costs incurred during the first quarter of 2012, related to the pending acquisition of CH Energy Group
- Lower finance charges, primarily due to higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion
Unfavourable
- Higher preference share dividends, due to the issuance of First Preference Shares, Series J in November 2012
- Lower income tax recovery, due to higher Part VI.1 taxes and the release of an income tax provision at FHI in the first quarter of 2012
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 2013 are summarized as follows.
| NATURE OF REGULATION |
| |
|
|
|
|
Allowed Returns (%) |
|
Supportive Features |
Regulated
Utility |
|
Regulatory
Authority |
|
Allowed
Common
Equity
(%) |
2011 |
2012 |
2013 |
|
Future or Historical Test Year
Used to Set Customer Rates |
| |
|
|
|
|
|
ROE |
|
|
COS/ROE |
| FEI |
|
British Columbia Utilities Commission
("BCUC")
|
|
40(1)
|
9.50
|
9.50
|
9.50(1)
|
|
FEI: Prior to January 1, 2010, 50/50 sharing of earnings above or below the allowed ROE under a PBR mechanism that expired on December 31, 2009 with a two-year phase-out
|
| FEVI |
|
BCUC
|
|
40(1)
|
10.00
|
10.00
|
10.00(1)
|
|
|
| FEWI |
|
BCUC
|
|
40(1)
|
10.00
|
10.00
|
10.00(1)
|
|
ROEs established by the BCUC -
2013 ROEs are under review |
| |
|
|
|
|
|
|
|
|
Future Test Year |
FortisBC-
Electric |
|
BCUC
|
|
40(1)
|
9.90
|
9.90
|
9.90(1)
|
|
COS/ROE
|
| |
|
|
|
|
|
|
|
|
PBR mechanism for 2009 through 2011: 50/50 sharing of earnings above or below the allowed ROE up to an achieved ROE that is 200 basis points above or below the allowed ROE - excess to deferral account |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
ROE established by the BCUC -
2013 ROE is under review |
| |
|
|
|
|
|
|
|
|
Future Test Year |
Fortis-
Alberta |
|
Alberta Utilities
Commission ("AUC") |
|
41(1)
|
8.75
|
8.75
|
8.75(1)
|
|
COS/ROE
|
| |
|
|
|
|
|
|
|
|
PBR mechanism for 2013 through
2017 with capital tracker account
and other supportive features |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
ROE established by the AUC - 2013 ROE is under review |
| |
|
|
|
|
|
|
|
|
2012 test year with 2013 through
2017 rates set using PBR mechanism |
Newfound-
land Power |
|
Newfoundland and
Labrador Board of
Commissioners of
Public Utilities
("PUB")
|
|
45
|
8.38 +/-
50 bps
|
8.80 +/-
50 bps
|
8.80 +/-
50 bps
|
|
COS/ROE
The allowed ROE was set using an
automatic adjustment formula tied
to long-term Canada bond yields for 2011. ROE established by the PUB for 2012 through 2015 |
| |
|
|
|
|
|
|
|
|
Future Test Year |
Maritime-
Electric |
|
Island Regulatory and Appeals Commission |
|
40
|
9.75
|
9.75
|
9.75
|
|
COS/ROE |
| Future Test Year |
Fortis-
Ontario |
|
Ontario Energy Board ("OEB") Canadian Niagara Power |
|
40
|
8.01
|
8.01
|
8.93(2)
|
|
Canadian Niagara Power - COS/ROE
Algoma Power - COS/ROE and
subject to Rural and Remote Rate |
| |
|
Algoma Power |
|
40 |
9.85 |
9.85 |
9.85(2) |
|
Protection ("RRRP") program |
| |
|
|
|
|
|
|
|
|
|
| |
|
Franchise Agreement
Cornwall Electric |
|
|
|
|
|
|
Cornwall Electric - Price cap with
commodity cost flow through |
| |
|
|
|
|
|
|
|
|
Canadian Niagara Power - 2009
test year for 2011 and 2012; 2013
test year for 2013
Algoma Power - 2011 test year for
2011, 2012 and 2013 |
| |
|
|
|
|
|
ROA |
|
|
COS/ROA |
Caribbean-
Utilities |
|
Electricity Regulatory
Authority ("ERA")
|
|
N/A
|
7.75 -
9.75
|
7.25 -
9.25
|
7.25 -
9.25(3)
|
|
Rate-cap adjustment mechanism
("RCAM") 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 the
Turks and Caicos
Islands
|
|
N/A
|
17.50(4)
|
17.50(4)
|
17.50(4)
|
|
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) |
Capital structures and allowed ROEs for 2013 are interim and are subject to change based on the outcomes of cost of capital proceedings |
| |
|
| (2) |
Based on the ROE automatic adjustment formula, the allowed ROE for regulated electric utilities in Ontario is 8.93% for 2013. This ROE is not applicable to the regulated electric utilities until they are scheduled to file full COS rate applications. As a result, the allowed ROE of 8.93% is not applicable to Algoma Power in 2013. |
| |
|
| (3) |
Subject to change in June 2013 based on the annual operation of the RCAM |
| |
|
| (4) |
Amount provided under licences as it relates to FortisTCI and Atlantic. Amount provided 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 electricity rates associated with significant capital investment in recent years. |
| |
|
| |
|
| |
|
| MATERIAL REGULATORY DECISIONS AND APPLICATIONS |
| Regulated Utility |
|
Summary Description |
| FEI/FEVI/FEWI |
|
- Effective January 1, 2013, rates increased by approximately 1.6% for typical residential customers at FEI in the Lower Mainland, as a result of an increase in delivery rates in accordance with the BCUC's decision in April 2012 pertaining to the FortisBC Energy companies' 2012/2013 Revenue Requirements Application ("RRA"), partially offset by a decrease in midstream rates. Natural gas commodity rates remained unchanged for customers at FEI, effective January 1, 2013.
- Effective January 1, 2013, rates increased approximately 5% for typical customers at FEWI, as a result of an increase in delivery rates, in accordance with the BCUC's decision in April 2012 pertaining to the FortisBC Energy companies' 2012/2013 RRA, and an increase in natural gas commodity rates.
- In February 2012 the BCUC approved FEI's amended application for a general tariff for the provision of compressed natural gas and liquefied natural gas ("LNG") refuelling services for transportation vehicles. FEI's application for changing its LNG sales and dispensing service rate schedule from a pilot program to a permanent program is pending before the BCUC. A decision on the application is expected in the second quarter of 2013.
- In August 2011 FEI received a BCUC decision on the use of Energy Efficiency and Conservation ("EEC") funds as incentives for natural gas-fuelled vehicles ("NGVs"). FEI had made these funds available to assist large customers in purchasing NGVs in lieu of vehicles fuelled by diesel. The decision determined that it was not appropriate to use EEC funds for the above-noted purpose and the BCUC requested that FEI provide further submissions to determine the prudency of the EEC incentives. In August 2012 an application was filed with the BCUC to review the prudency of the EEC incentives totalling approximately $6 million. A decision was received in April 2013 in which the BCUC determined that the EEC incentives for NGVs were prudently incurred and can be recovered from customers in rates.
- During the first quarter of 2013, the BCUC approved the capital expenditures for the Telus Garden project at FortisBC Alternative Energy Services Inc. ("FAES"); however, approval of revisions to the rate design and rates is pending. There has been no change in the status of the other projects at FAES from that disclosed in the Corporation's 2012 Annual MD&A.
|
| |
|
- In April 2012 the FortisBC Energy companies applied to the BCUC for the necessary approvals to amalgamate the three utilities and implement common rates across the service territories served by the amalgamated entity, effective January 1, 2014. The BCUC issued its decision in February 2013 denying the request to implement common rates. The FortisBC Energy companies filed a leave to appeal the decision to the British Columbia Court of Appeal in March 2013 and filed an Application for Reconsideration with the BCUC in April 2013.
- The public oral hearing for the first phase of a Generic Cost of Capital ("GCOC") Proceeding to determine the allowed ROE and appropriate capital structure for FEI, the designated low-risk benchmark utility in British Columbia, occurred in December 2012. A decision on the proceeding is expected mid-2013. Effective January 1, 2013, as ordered by the BCUC in December 2012, the current allowed ROE and capital structure for FEI and all other regulated entities in British Columbia that rely on the benchmark utility to establish rates are to be maintained and made interim. FEVI, FEWI and FortisBC Electric will have their allowed ROEs and capital structures determined in the second phase of the GCOC Proceeding. In March 2013 the BCUC initiated the second phase of the GCOC Proceeding by establishing a procedural conference, which took place in April 2013. The results of the GCOC Proceeding could materially impact the earnings of the FortisBC Energy companies and FortisBC Electric. For further discussion on the nature of the GCOC Proceeding, refer to the "Material Regulatory Decisions and Applications" section of the Corporation's 2012 Annual MD&A. |
| FortisBC Electric |
|
- Effective January 1, 2013, as approved by the BCUC in its August 2012 decision pertaining to FortisBC Electric's 2012/2013 RRA, customer electricity rates increased 4.2%.
- In July 2012 FortisBC Electric filed its Advanced Metering Infrastructure ("AMI") Application, which was updated in early 2013. A regulatory review by the BCUC and various interveners concluded with an oral hearing in March 2013. A decision on the application is expected in the second half of 2013. The AMI project proposes to improve and modernize FortisBC Electric's grid by exchanging its manually read meters with advanced meters. The AMI project is expected to cost approximately $52 million.
- In March 2013 the BCUC approved the acquisition by FortisBC Electric of the City of Kelowna's electrical utility assets and allowed for approximately $38 million of the $55 million purchase price to be included in FortisBC Electric's rate base, resulting in the recognition of approximately $14 million of goodwill. The transaction closed in March 2013, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. Prior to the acquisition, FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.
- In March 2012 the BCUC issued an order establishing a written hearing process to review the prudency of approximately $29 million in capital expenditures already incurred related to the Kettle Valley Distribution Source Project, which was substantially completed in 2009. In April 2013 the BCUC issued a decision approving substantially all of the $29 million to be included in rate base, effective from January 1, 2012. |
| FortisAlberta |
|
- In September 2012 the AUC issued a generic PBR Decision outlining the PBR framework applicable to distribution utilities in Alberta, including FortisAlberta, for a five-year term, which commenced January 1, 2013. In the PBR Decision, a formula that estimates inflation annually and assumes productivity improvements is to be used by the distribution utilities to determine customer rates on an annual basis. The PBR framework also includes mechanisms for the recovery or settlement of items determined to flow through directly to customers and the recovery of costs related to capital expenditures that are not being recovered through the inflationary factor of the formula. The AUC also approved: (i) a Z factor permitting an application for recovery of costs related to significant unforeseen events; (ii) a PBR re-opener mechanism permitting an application to re-open and review the PBR plan to address specific problems with the design or operation of the PBR plan; and (iii) an ROE efficiency carry-over mechanism permitting an efficiency incentive by allowing the utility to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of the term. The PBR formula does, however, raise some concern and uncertainty for FortisAlberta regarding the treatment of certain capital expenditures. While the PBR Decision did provide for a capital tracker mechanism for the recovery of costs related to certain capital expenditures, FortisAlberta sought further clarification regarding this mechanism in a Review and Variance ("R&V") Application and a Capital Tracker Application and sought leave to appeal the issue to the Alberta Court of Appeal.
|
| |
|
- In March 2013 the AUC issued a decision denying the R&V Application. FortisAlberta has filed a leave to appeal the decision on similar grounds as the leave to appeal the 2012 PBR Decision. Both appeals have been adjourned pending further determinations in outstanding PBR-related proceedings.
- In March 2013 the AUC issued an interim decision regarding the Compliance Applications filed by the distribution utilities in Alberta. The interim decision approved a combined inflation and productivity factor of 1.71%, certain adjustments to the Company's going-in rates, including specific flow-through amounts, and the recovery, on an interim basis, of 60% of the revenue requirement associated with the 2013 capital tracker expenditures applied for to provide a reasonable balance between the utilities' forecasted 2013 customer rate adjustments related to the capital trackers and potential customer rate-shock implications. For FortisAlberta, the AUC approved approximately $14.5 million of the $24 million in revenue requested in its 2013 Capital Tracker Application. The decision resulted in an interim increase in FortisAlberta's distribution rates of approximately 4%, effective January 1, 2013, with collection from customers commencing April 1, 2013. A final decision on the Compliance Application, with any subsequent adjustments to 2013 customer distribution rates, is expected in the third quarter of 2013. A hearing on the Capital Tracker Application is expected in June 2013, with a decision expected in the second half of 2013.
- In October 2012 the AUC initiated a 2013 GCOC Proceeding to establish the final allowed ROE for 2013 and determine whether a formulaic ROE automatic adjustment mechanism should be re-established. In November 2012 the 2013 GCOC Proceeding was suspended until other regulatory matters were resolved. In April 2013 the AUC recommenced the 2013 GCOC Proceeding to set the allowed ROE and capital structure for distribution utilities in Alberta for 2013 as well as the allowed ROE for 2014. In addition, an interim allowed ROE for 2015 will be established. The AUC does not intend to consider the possibility of re-establishing a formulaic ROE automatic adjustment mechanism at this time. The process for the 2013 GCOC Proceeding is scheduled to commence in the second quarter of 2013 with a hearing scheduled for early 2014. The expected outcome of this proceeding is currently unknown.
- In its 2011 GCOC Decision, the AUC made statements regarding cost responsibility for stranded assets, which FortisAlberta and other utilities challenged as being incorrectly made. As a result, FortisAlberta together with other Alberta utilities filed an R&V Application with the AUC. In June 2012 the AUC decided it would not permit an R&V of the decision in question but would examine the issue in the Utility Asset Disposition ("UAD") Proceeding, which was reinitiated in November 2012. FortisAlberta and the other Alberta utilities had also sought leave to appeal the stranded asset pronouncements to the Alberta Court of Appeal and temporarily adjourned that court process pending the AUC's follow-up proceeding. Any decision by the AUC regarding the treatment of stranded assets does not alter a utility's right to a reasonable opportunity to recover prudent COS and the right to earn a reasonable ROE. In June 2013 FortisAlberta, together with other Alberta utilities, will file reply arguments in the UAD Proceeding, after which time the AUC will commence deliberations with a decision expected in the third quarter of 2013. |
Newfound-
land Power |
|
- In April 2013 the PUB issued its decision related to Newfoundland Power's 2013/2014 General Rate Application ("GRA"), which was filed in September 2012, to establish the Company's cost of capital for rate-making purposes. In its decision, the PUB ordered that the allowed ROE and common equity component of capital structure remain at 8.8% and 45%, respectively, for 2013 through 2015. The PUB also ordered: (i) the recognition of pension expense for regulatory purposes in accordance with US GAAP and the related regulatory asset to be recovered from customers over 15 years; (ii) a decrease in the overall composite depreciation rate to 3.42% from 3.47%; (iii) the deferral of annual customer energy conservation program costs to be recovered from customers over the subsequent seven-year period; and (iv) the approval of various regulatory amortizations over a three-year period, including cost-recovery deferrals recognized in 2011 and 2012, costs associated with the GRA and the December 31, 2011 balance in the Weather Normalization Account. The impact of the decision is expected to increase customer electricity rates, effective January 1, 2013, by an overall average of approximately 5%, with collection from customers commencing July 1, 2013. The cumulative impact of the decision will be recorded in the second quarter of 2013, when the decision was received, with the impact of the decision related to the first quarter of 2013 determined to be immaterial.
|
| |
|
- Through the annual operation of Newfoundland Hydro's Rate Stabilization Plan, variances in the cost of fuel used to generate electricity that Newfoundland Hydro sells to Newfoundland Power are captured and flowed through to customers through the operation of Newfoundland Power's Rate Stabilization Account ("RSA"). Customer electricity rates are expected to decrease approximately 8%, effective July 1, 2013, due to a decrease in the forecasted cost of oil to be used to generate electricity at Newfoundland Hydro. The RSA also captures variances in certain of Newfoundland Power's costs, such as pension and energy supply costs. The above-noted expected decrease in customer rates is not expected to impact Newfoundland Power's earnings in 2013.
- Newfoundland Power plans to file an application with the PUB in May 2013 to reduce customer electricity rates by an overall average of approximately 3%, effective July 1, 2013, as a result of the net impact of the GRA decision and annual operation of the RSA.
- Newfoundland Power is required to file its GRA for 2016 on or before June 1, 2015. |
| Maritime Electric |
|
- In December 2012 the Electric Power (Energy Accord Continuation) Amendment Act ("Accord Continuation Act") was enacted, which sets out the inputs, rates and other terms for the continuation of the PEI Energy Accord ("Accord") for an additional three years covering the period March 1, 2013 through February 29, 2016. Under the terms of the Accord Continuation Act, Maritime Electric received, in March 2013, proceeds of approximately $47 million from the Government of PEI upon its assumption of Maritime Electric's $47 million regulatory asset related to certain deferred incremental replacement energy costs during the refurbishment of Point Lepreau. Over the above-noted three-year period, increases in electricity costs for a typical residential customer have been set at 2.2%, effective March 1 annually, and Maritime Electric's allowed ROE has been capped at 9.75% each year. The resulting customer rate increases are due to the collection from customers by Maritime Electric, acting as an agent on behalf of the Government of PEI, of Point Lepreau-related costs assumed by the Government of PEI and higher COS. The proceeds were used by Maritime Electric to repay short-term borrowings, pay a special dividend to Fortis to maintain the utility's capital structure and to finance its capital expenditure program. |
| FortisOntario |
|
- Effective January 1, 2013, residential customer rates in Fort Erie, Gananoque and Port Colborne increased by an average 6.8%, 5.9% and 7.4%, respectively. The rate increases were the result of the OEB's decision pertaining to FortisOntario's 2013 COS Application using a 2013 forward test year and the recovery of smart meter costs and stranded assets related to conventional meters and reflect an allowed ROE of 8.93%.
- In March 2013 the OEB issued its decision on Algoma Power's Third-Generation Incentive-Rate Mechanism Application for customer electricity distribution rates and smart meter cost recovery, effective January 1, 2013, resulting in an overall increase in residential and commercial customer distribution rates of 3.75%. Residential and commercial customer distribution rates are adjusted by the average increase in customer rates of all other distributor rate changes in Ontario in the most recent rate year. The difference in the recovery of COS in residential and commercial customer distribution rates and the revenue requirement is compensated from RRRP program funding. Recovery of smart meter costs allocated to residential customers will also be recovered from RRRP program funding as ordered by the OEB. Total RRRP program funding for 2013 is expected to be approximately $12 million. |
| Caribbean Utilities |
|
- A Certificate of Need was filed with the ERA by Caribbean Utilities in November 2011. In March 2012 proposals for the installation of new generation units from six qualified bidders, including Caribbean Utilities, was requested by the ERA and Caribbean Utilities' proposal was submitted in July 2012. In February 2013 the ERA awarded the bid to develop, install and operate two new 18-MW generation units to a third party. In April 2013 the ERA announced that it will be engaging an independent party to conduct an investigation of irregularities in the bid process. The details of the investigation have not yet been disclosed. Caribbean Utilities is continuing its review of the ERA's analysis of the bids. |
| Fortis Turks and Caicos |
|
- In March 2013 the Fortis Turks and Caicos utilities submitted their 2012 annual regulatory filings outlining performance in 2012. Included in the filings were the calculations, in accordance with the utilities' licences, of rate base of US$195 million for 2012 and cumulative shortfall in achieving allowable profits of US$105 million as at December 31, 2012. |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2013 and December 31, 2012.
| Significant Changes in the Consolidated Balance Sheets (Unaudited) between March 31, 2013 and December 31, 2012 |
| Balance Sheet Account |
|
Increase/
(Decrease)
($ millions) |
Explanation |
| Accounts receivable |
|
88 |
The increase was primarily due to: (i) the operation of equal payment plans for customers, mainly at the FortisBC Energy companies and Newfoundland Power; (ii) the receivable recognized in March 2013 upon the settlement of expropriation matters associated with Exploits Partnership; and (iii) the impact of a seasonal increase in electricity sales. The increase was partially offset by lower unbilled revenue accruals at the FortisBC Energy companies, due to lower average consumption as a result of warmer temperatures. |
| Inventories |
|
(55) |
The decrease was driven by 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 |
|
(27) |
The decrease was mainly due to: (i) proceeds of approximately $47 million received from the Government of PEI upon its assumption of Maritime Electric's regulatory asset associated with certain deferred incremental replacement energy costs during the refurbishment of Point Lepreau; and (ii) the $23 million change in the deferral of the fair market value of the natural gas derivatives at the FortisBC Energy companies. The above decreases were partially offset by higher regulatory deferred income taxes and an increase in the deferral of various other costs, as permitted by the regulators, mainly at the FortisBC utilities and FortisAlberta. |
| Utility capital assets |
|
156 |
The increase primarily related to: (i) $230 million invested in electricity and gas systems; (ii) the acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric; and (iii) the impact of foreign exchange on the translation of US dollar-denominated utility capital assets. The above increases were partially offset by depreciation and customer contributions for the three months ended March 31, 2013. |
| Short-term borrowings |
|
(47) |
The decrease was primarily due to a reduction in borrowings at the FortisBC Energy companies due to the seasonality of operations, and the repayment of borrowings at Maritime Electric with a portion of proceeds received from the Government of PEI in March 2013, as discussed above. |
| Accounts payable and other current liabilities |
|
(80) |
The decrease was mainly due to: (i) the timing of Alberta Electric System Operator ("AESO") payments for transmission costs and lower accounts payable associated with transmission-connected projects at FortisAlberta; and (ii) the $23 million change in the fair market value of the natural gas derivatives at the FortisBC Energy companies. |
| Regulatory liabilities - current and long-term |
|
53 |
The increase was mainly due to a higher AESO charges deferral at FortisAlberta and an increase in the rate stabilization accounts at the FortisBC Energy companies. |
| Long-term debt (including current portion) |
|
114 |
The increase was primarily due to higher committed credit facility borrowings at FortisAlberta, the Corporation, FortisBC Electric and Newfoundland Power. The committed credit facility borrowings were largely in support of energy infrastructure investment, including the construction of the Waneta Expansion, and the acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric. The increase was partially offset by regularly scheduled debt repayments at the FortisBC Energy companies and Fortis Properties. |
| Shareholders' equity (before non-controlling interests) |
|
122 |
The increase was primarily due to net earnings attributable to common equity shareholders for the three months ended March 31, 2013, less dividends declared on common shares, and the issuance of common shares under the Corporation's dividend reinvestment, stock option and employee share purchase plans. |
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2013, as compared to the same period in 2012, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows (Unaudited) |
Quarter Ended March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
Variance |
|
| Cash, Beginning of Period |
154 |
|
87 |
|
67 |
|
| Cash Provided by (Used in): |
|
|
|
|
|
|
| |
Operating Activities |
280 |
|
328 |
|
(48 |
) |
| |
Investing Activities |
(289 |
) |
(211 |
) |
(78 |
) |
| |
Financing Activities |
23 |
|
(94 |
) |
117 |
|
| Cash, End of Period |
168 |
|
110 |
|
58 |
|
Operating Activities: Cash flow from operating activities was $48 million lower quarter over quarter. The decrease was primarily due to unfavourable changes in working capital at FortisAlberta and the FortisBC Energy companies, associated with accounts payable and other current liabilities and current regulatory deferral accounts, partially offset by favourable working capital changes related to regulatory deferrals at Maritime Electric. Higher earnings quarter over quarter were partially offset by unfavourable changes in deferred income taxes attributable to regulatory deferrals and tax loss utilization.
Investing Activities: Cash used in investing activities was $78 million higher quarter over quarter. The increase was driven by FortisBC Electric's acquisition of electrical utility assets from the City of Kelowna in March 2013 for approximately $55 million, and higher capital spending at FortisAlberta, largely due to higher AESO capital contributions quarter over quarter.
Financing Activities: Cash provided by financing activities was $117 million higher quarter over quarter. The increase was primarily due to: (i) higher net borrowings under committed credit facilities classified as long-term; (ii) lower net repayments of short-term borrowings; and (iii) higher proceeds from the issuance of common shares. The above items were partially offset by higher repayments of long-term debt and a decrease in advances received from non-controlling interests.
Net repayments of short-term borrowings were $35 million lower quarter over quarter. The decrease was mainly due to the FortisBC Energy companies, partially offset by an increase in net repayments of short-term borrowings at Maritime Electric. A portion of the cash proceeds received by Maritime Electric from the Government of PEI, upon the assumption of the utility's regulatory asset related to certain deferred Point Lepreau replacement energy costs, was used to repay short-term borrowings in the first quarter of 2013.
Repayments of long-term debt and capital lease and finance obligations, and net borrowings (repayments) under committed credit facilities for the quarter compared to the same quarter last year are summarized in the following tables.
| Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited) |
|
| |
Quarter Ended March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
Variance |
|
| FortisBC Energy Companies |
(21 |
) |
(1 |
) |
(20 |
) |
| Caribbean Utilities |
(1 |
) |
(1 |
) |
- |
|
| Fortis Properties |
(18 |
) |
(2 |
) |
(16 |
) |
| Total |
(40 |
) |
(4 |
) |
(36 |
) |
| |
| |
| |
| Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited) |
| |
Quarter Ended March 31 |
| ($ millions) |
2013 |
2012 |
|
Variance |
| FortisAlberta |
48 |
(29 |
) |
77 |
| FortisBC Electric |
32 |
(9 |
) |
41 |
| Newfoundland Power |
21 |
14 |
|
7 |
| Corporate |
35 |
31 |
|
4 |
| Total |
136 |
7 |
|
129 |
Borrowings under credit facilities by the utilities are primarily in support of their 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 of approximately $22 million were received during the first quarter of 2013 from non-controlling interests in the Waneta Expansion Limited Partnership ("Waneta Partnership") to finance capital spending related to the Waneta Expansion, compared to $29 million received during the first quarter of 2012. In January 2012 advances of approximately $12 million were received from two First Nations bands, representing their 15% equity investment in the LNG storage facility on Vancouver Island.
Proceeds from the issuance of common shares were $8 million higher quarter over quarter, reflecting an increase in the number of shares issued under the Corporation's stock option and employee share purchase plans.
Common share dividends paid during the first quarter of 2013 were $41 million, net of $19 million of dividends reinvested, compared to $44 million, net of $13 million of dividends reinvested, paid during the same quarter of 2012. The dividend paid per common share for the first quarter of 2013 was $0.31 compared to $0.30 for the first quarter of 2012. The weighted average number of common shares outstanding for the first quarter was 192.0 million, compared to 189.0 million for the first quarter of 2012.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at March 31, 2013, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2012 Annual MD&A and below, where applicable.
| Contractual Obligations (Unaudited) |
|
Due |
|
|
|
|
Due |
| As at March 31, 2013 |
|
within |
Due in |
Due in |
Due in |
Due in |
after |
| ($ millions) |
Total |
1 year |
year 2 |
year 3 |
year 4 |
year 5 |
5 years |
| Long-term debt |
6,014 |
81 |
693 |
280 |
314 |
103 |
4,543 |
| Government loan obligations |
29 |
4 |
10 |
10 |
5 |
- |
- |
| Capital lease and finance obligations |
2,587 |
48 |
49 |
49 |
50 |
51 |
2,340 |
| Interest obligations on long-term debt |
6,618 |
355 |
336 |
313 |
286 |
272 |
5,056 |
| Gas purchase contract obligations (1) |
225 |
225 |
- |
- |
- |
- |
- |
| Power purchase obligations |
|
|
|
|
|
|
|
| |
FortisBC Electric |
29 |
11 |
7 |
6 |
3 |
2 |
- |
| |
FortisOntario |
346 |
47 |
49 |
50 |
52 |
53 |
95 |
| |
Maritime Electric |
131 |
38 |
41 |
37 |
1 |
1 |
13 |
| Capital cost (2) |
497 |
17 |
18 |
18 |
18 |
17 |
409 |
| Operating lease obligations |
22 |
4 |
4 |
3 |
3 |
3 |
5 |
| Waneta Partnership promissory note |
72 |
- |
- |
- |
- |
- |
72 |
| Joint-use asset and shared service agreements |
62 |
4 |
3 |
3 |
3 |
3 |
46 |
| Defined benefit pension funding contributions |
75 |
35 |
15 |
12 |
9 |
1 |
3 |
| Performance Share Unit Plan obligations |
2 |
1 |
- |
1 |
- |
- |
- |
| Other |
6 |
2 |
1 |
- |
- |
- |
3 |
| Total |
16,715 |
872 |
1,226 |
782 |
744 |
506 |
12,585 |
| |
|
| (1) |
Based on index prices as at March 31, 2013 |
| |
|
| (2) |
Maritime Electric has entitlement to approximately 4.7% of the output from Point Lepreau for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit. A major refurbishment of Point Lepreau that began in 2008 was completed and the facility returned to service in November 2012. The refurbishment is expected to extend the facility's estimated life an additional 27 years and, as a result, the total estimated capital cost obligation has increased approximately $51 million from that disclosed in the 2012 Annual MD&A. |
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2012 Annual MD&A, except as described as follows.
In March 2013 FortisBC Electric acquired the City of Kelowna's electrical utility assets for approximately $55 million. For further information, refer to the "Significant Items" section of this MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program, which is not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40% equity, including preference shares, and 60% debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure (Unaudited) |
As at |
| |
March 31, 2013 |
December 31, 2012 |
| |
($ millions) |
(%) |
($ millions) |
(%) |
| Total debt and capital lease and finance obligations (net of cash) (1) |
6,376 |
55.0 |
6,317 |
55.3 |
| Preference shares |
1,108 |
9.5 |
1,108 |
9.7 |
| Common shareholders' equity |
4,114 |
35.5 |
3,992 |
35.0 |
| Total (2) |
11,598 |
100.0 |
11,417 |
100.0 |
| |
|
| (1) |
Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash |
| |
|
| (2) |
Excludes amounts related to non-controlling interests |
The change in the capital structure was primarily due to: (i) net earnings attributable to common equity shareholders, net of dividends declared; (ii) common shares issued, mainly under the Corporation's dividend reinvestment, stock option and employee share purchase plans; and (iii) lower short-term borrowings. The capital structure was also impacted by an increase in long-term debt, mainly due to higher borrowings under committed credit facilities, largely in support of energy infrastructure investment, partially offset by regularly scheduled debt repayments.
Excluding capital lease and finance obligations, the Corporation's capital structure as at March 31, 2013 was 53.2% debt, 9.9% preference shares and 36.9% common shareholders' equity (December 31, 2012 - 53.6% debt, 10.1% preference shares and 36.3% common shareholders' equity).
CREDIT RATINGS
The Corporation's credit ratings are as follows:
| Standard & Poor's ("S&P") |
A- (long-term corporate and unsecured debt credit rating) |
| DBRS |
A(low) (unsecured debt credit rating) |
In February 2013 S&P and DBRS affirmed the Corporation's debt credit ratings. 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, management's commitment to maintaining low levels of debt at the holding company level, the Corporation's reasonable credit metrics and its demonstrated ability and continued focus on acquiring and integrating stable regulated utility businesses financed on a conservative basis. The credit ratings also reflect the Corporation's financing plans for the pending acquisition of CH Energy Group and the expected completion of the Waneta Expansion on time and on budget.
CAPITAL EXPENDITURE PROGRAM
Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred.
A breakdown of the $250 million in gross consolidated capital expenditures by segment for the first quarter of 2013 is provided in the following table.
| Gross Consolidated Capital Expenditures (Unaudited) (1) |
|
|
| Quarter Ended March 31, 2013 |
|
|
|
| ($ millions) |
|
|
|
FortisBC
Energy
Companies |
Fortis
Alberta |
FortisBC
Electric |
Newfoundland
Power |
Other
Regulated
Electric
Utilities -
Canadian |
Total
Regulated
Utilities -
Canadian |
Regulated
Electric
Utilities -
Caribbean |
Non-
Regulated -
Fortis
Generation |
Non-
Regulated -
Fortis
Properties |
Total |
| 38 |
95 |
17 |
15 |
13 |
178 |
11 |
48 |
13 |
250 |
| |
|
| (1) |
Relates to cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as reflected on the consolidated statement of cash flows. Excludes capitalized depreciation and amortization and non-cash equity component of AFUDC. |
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts.
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 2012 Annual MD&A. Gross consolidated capital expenditures for 2013 are forecasted at approximately $1.3 billion.
Construction of the $900 million Waneta Expansion is ongoing, with an additional $47 million spent in the first quarter of 2013. To date, approximately $483 million has been spent on the Waneta Expansion since construction began late in 2010. Key construction activities during the first quarter of 2013 included ongoing placement of concrete in the powerhouse and intake, ongoing installation of the powerhouse roof and turbine components, and intake-channel excavation work.
Over the five-year period 2013 through 2017, gross consolidated capital expenditures, including expenditures at Central Hudson Gas & Electric Corporation ("Central Hudson"), are expected to be approximately $6 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 54% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 20% at Canadian Regulated Gas Utilities; 11% at Central Hudson; 4% at Caribbean Regulated Electric Utilities; and the remaining 11% 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: 36% to meet customer growth, 41% for sustaining capital expenditures, and 23% 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.
As at March 31, 2013, management expects consolidated long-term debt maturities and repayments to average approximately $295 million annually over the next five years. 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.
In May 2012 Fortis filed a base shelf prospectus under which Fortis may offer, from time to time during the 25-month period from May 10, 2012, by way of a prospectus supplement, common shares, preference shares, subscription receipts and/or unsecured debentures in the aggregate amount of up to $1.3 billion (or the equivalent in US dollars or other currencies). The base shelf prospectus provides the Corporation with flexibility to access securities markets in a timely manner. The nature, size and timing of any offering of securities under the Corporation's base shelf prospectus will be consistent with the past capital-raising practices of the Corporation and continue to be dependent upon the Corporation's assessment of its requirements for funding and general market conditions.
To finance a portion of the Corporation's pending acquisition of CH Energy Group, Fortis offered and sold, by way of a prospectus supplement, approximately $601 million of Subscription Receipts in June 2012 under a bought-deal offering with a syndicate of underwriters. Fortis also closed an offering of approximately $200 million First Preference Shares, Series J in November 2012, by way of a prospectus supplement, under the above-noted base shelf prospectus.
Fortis and its subsidiaries were compliant with debt covenants as at March 31, 2013 and are expected to remain compliant throughout 2013.
CREDIT FACILITIES
As at March 31, 2013, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.4 billion, of which $2.0 billion was unused, including $910 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 $2.3 billion of the total credit facilities are committed facilities with maturities ranging from 2013 through 2017.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities (Unaudited) |
|
|
|
|
As at |
|
| |
Regulated |
|
Fortis |
Corporate |
|
March 31, |
|
December 31, |
|
| ($ millions) |
Utilities |
|
Properties |
and Other |
|
2013 |
|
2012 |
|
| Total credit facilities |
1,383 |
|
13 |
1,030 |
|
2,426 |
|
2,460 |
|
| Credit facilities utilized: |
|
|
|
|
|
|
|
|
|
| |
Short-term borrowings |
(89 |
) |
- |
- |
|
(89 |
) |
(136 |
) |
| |
Long-term debt (including current portion) |
(178 |
) |
- |
(88 |
) |
(266 |
) |
(150 |
) |
| Letters of credit outstanding |
(66 |
) |
- |
(2 |
) |
(68 |
) |
(67 |
) |
| Credit facilities unused |
1,050 |
|
13 |
940 |
|
2,003 |
|
2,107 |
|
As at March 31, 2013 and December 31, 2012, 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 January 2013 FEVI's $20 million unsecured committed non-revolving credit facility matured and was not replaced.
In April 2013 FortisBC Electric renegotiated and amended its credit facility agreement resulting in an extension to the maturity of the Company's $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2016 and $50 million now maturing in May 2014. The amended credit facility agreement contains substantially similar terms and conditions as the previous credit facility agreement.
In April 2013 FHI extended its $30 million unsecured committed revolving credit facility to mature in May 2014 from May 2013. The new agreement contains substantially similar terms and conditions as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| Financial Instruments (Unaudited) |
As at |
| |
March 31, 2013 |
December 31, 2012 |
| |
Carrying |
Estimated |
Carrying |
Estimated |
| ($ millions) |
Value |
Fair Value |
Value |
Fair Value |
| Waneta Partnership promissory note |
48 |
52 |
47 |
51 |
| Long-term debt, including current portion |
6,014 |
7,332 |
5,900 |
7,338 |
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) by 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 $106 million as at March 31, 2013 (December 31, 2012 - $104 million).
Risk Management: The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above-noted exposure through the use of US dollar 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 Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and Belize Electric Company Limited ("BECOL") is the US dollar.
As at March 31, 2013, the Corporation's corporately issued US$557 million (December 31, 2012 - US$557 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at March 31, 2013, the Corporation had approximately US$16 million (December 31, 2012 - US$17 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 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 from 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 $2 million during the three months ended March 31, 2013 ($1.5 million foreign exchange loss for the three months ended March 31, 2012).
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and fuel and natural gas prices through the use of derivative instruments. The Corporation and its subsidiaries do not hold or issue derivative instruments for trading purposes. As at March 31, 2013, the Corporation's derivative contracts consisted of fuel option contracts, natural gas swap and option contracts, and gas purchase contract premiums. The fuel option contracts are held by Caribbean Utilities and the remaining derivative instruments are held by the FortisBC Energy companies.
The following table summarizes the Corporation's derivative instruments.
| Derivative Instruments (Unaudited) |
As at |
|
| |
|
|
|
March 31, |
|
December 31, |
|
| |
|
|
|
2013 |
|
2012 |
|
Liability |
Maturity |
Number of
Contracts |
Volume (1) |
Carrying Value (2)
($ millions) |
|
Carrying Value (2)
($ millions) |
|
| Fuel option contracts (3) |
2013 |
6 |
13 |
- |
|
(1 |
) |
| Natural gas derivatives: |
|
|
|
|
|
|
|
| Gas swaps and options |
2014 |
35 |
19 |
(33 |
) |
(51 |
) |
| Gas purchase contract premiums |
2014 |
46 |
80 |
(3 |
) |
(8 |
) |
| |
|
| (1) |
The volume for fuel option contracts is reported in millions of imperial gallons and for natural gas derivatives is reported in petajoules. |
| |
|
| (2) |
Carrying value is estimated fair value. The liability represents the gross derivatives balance. |
| |
|
| (3) |
The carrying value of the fuel option contracts was less than $1 million as at March 31, 2013. |
The fuel option contracts are used by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company's Fuel Price Volatility Management Program. The fuel option contracts mature in April and October 2013. Approximately 70% of the Company's annual diesel fuel requirements are under fuel hedging arrangements.
The natural gas derivatives held by the FortisBC Energy companies are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts at the FortisBC Energy companies have floating, rather than fixed, prices. 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 in 2011, 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 maturity and the FortisBC Energy companies' ability to fully recover the commodity cost of gas in customer rates remains unchanged.
The changes in the fair values of the fuel option 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 values of the derivative instruments were recorded in accounts payable and other current liabilities as at March 31, 2013 and December 31, 2012.
The fair value of the fuel option contracts reflects only the value of the heating oil derivative and not the offsetting change in the value of the underlying future purchases of heating oil and was calculated using published market prices for heating oil or similar commodities where appropriate. 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 commodity cost of natural gas. The fair values of the fuel option 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.
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, 2013 (December 31, 2012 - $67 million), the Corporation had no off-balance sheet arrangements, such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities, that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
Year-to-date 2013, the business risks of the Corporation were consistent with those disclosed in the Corporation's 2012 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.
Regulatory Risk: The allowed ROE and capital structure at Newfoundland Power have been set for 2013 through 2015 and remain unchanged from 2012. Newfoundland Power plans to file an application in May 2013 to obtain final approval for customer electricity rates, effective January 1, 2013, commencing in July 2013 for collection from customers.
Final allowed ROEs and capital structure for 2013 remain outstanding for FortisBC and FortisAlberta. The results of cost of capital proceedings could materially impact the earnings of the above-noted utilities.
PBR commenced at FortisAlberta for a five-year term, which began January 1, 2013. In March 2013 interim distribution electricity rates under PBR were approved by the AUC in addition to the recovery, on an interim basis, of 60% of the revenue requirement associated with 2013 capital tracker expenditures applied for by FortisAlberta. While the AUC's 2012 PBR decision provides for a capital tracker mechanism to address recovery of certain capital expenditures outside of the PBR formula, the mechanism has yet to be tested to confirm its applicability to FortisAlberta's capital programs. Final decisions on FortisAlberta's rates are expected in the second half of 2013.
For further information, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Completion of the Acquisition of CH Energy Group: Fortis announced in February 2012 that it had entered into an agreement to acquire CH Energy Group for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson, is a regulated transmission and distribution utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. Approval of the acquisition by the PSC is the last significant matter required to close the transaction. A Settlement Agreement among Fortis, CH Energy Group, PSC Staff, registered interveners and other parties was filed with the PSC in January 2013. The parties to the Settlement Agreement have concluded that, based on the terms of the Settlement Agreement the acquisition is in the public interest and have recommended approval by the PSC. The deadline for submission of public comments in the proceeding was extended to May 1, 2013 by the PSC. On May 3, 2013 administrative law judges issued a Recommended Decision in connection with the acquisition asserting that without modification of the terms of the Settlement Agreement, the benefits of the acquisition are outweighed by perceived detriments remaining after mitigation. The Recommended Decision is an advisory opinion that will be considered by the PSC in determining whether to approve the acquisition. Submissions responding to the Recommended Decision are due by May 17, 2013 with responses to such submissions due by May 24, 2013. Fortis intends to engage in further discussions to obtain PSC approval of the acquisition. While no assurance regarding closing of the transaction can be given until an order is issued by the PSC, a final decision from the PSC regarding the acquisition and subsequent closing of the transaction is expected in June 2013. Based on the terms of the current Settlement Agreement, the acquisition is expected to be accretive to earnings per common share of Fortis within the first full year of ownership, excluding acquisition-related expenses.
A delay in receiving a PSC decision, and/or conditions imposed under such decision, may result in the failure to materialize some, or all, of the expected benefits of the acquisition of CH Energy Group, or such benefits may not occur 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.
Unless extended by agreement of both parties, the agreement and plan of merger between Fortis and CH Energy Group expires August 20, 2013.
A portion of the acquisition purchase price of CH Energy Group is expected to be funded from net proceeds from the $601 million Subscription Receipts offering, issued by the Corporation in June 2012, which proceeds are being held in escrow. The Subscription Receipts Agreement ("Agreement") contains a deadline of June 30, 2013 for the release of the proceeds from the offering. If it is determined that a PSC decision will not be received in time to allow closing of the acquisition of CH Energy Group to occur on or before June 30, 2013, Fortis may seek an extension of the June 30, 2013 deadline by way of amendment of the Agreement. The Agreement may be amended by a special resolution approved by at least two-thirds of the Subscription Receipts Holders ("Receipts Holders") at a meeting, either in person or by proxy, with a quorum for the meeting of at least two Receipts Holders collectively holding 25% of the Subscription Receipts. If conditions precedent to the closing of the transaction are not fulfilled or waived by June 30, 2013, or by the extension date for the Subscription Receipts if approved by Receipts Holders, or if the agreement and plan of merger related to the acquisition is terminated prior to such time, the proceeds from the Subscription Receipts offering, plus pro rata interest earned, are required to be returned to the Receipts Holders. As a result, closing of the transaction subsequent to June 30, 2013, or the extension date for the Subscription Receipts if approved by Receipts Holders, could result in the Corporation having to raise alternative capital to finance the acquisition.
Also, additional acquisition-related expenses in 2013 could be higher than those anticipated. Examples of expenses expected to be incurred include investment banker merger and acquisition advisory fees and consulting and legal fees.
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 reasonable 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 of the expropriated investment was $106 million, including foreign exchange impacts, as at March 31, 2013 (December 31, 2012 - $104 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) the ordering of the return of the shares to Fortis and/or award of damages; or (ii) the ordering of compensation to be paid to Fortis for the unconstitutional expropriation of the shares. Based on presently available information, the $106 million long-term other asset is not deemed impaired as at March 31, 2013. 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 April 30, 2013, Belize Electricity owed BECOL US$4 million for overdue energy purchases, representing approximately 20% of BECOL's annual sales to Belize Electricity. 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 in February 2013 and there were no changes in the credit ratings of the Corporation's utilities year-to-date 2013, except Maritime Electric's debt credit rating by S&P was updated from 'A- stable' to 'A stable'.
Defined Benefit Pension Plan Assets: As at March 31, 2013, the fair value of the Corporation's consolidated defined benefit pension plan assets was $900 million, up $32 million or 3.7%, from $868 million as at December 31, 2012.
Labour Relations: The collective agreement between employees in specified occupations in the areas of administration and operations support at the FortisBC Energy companies and the Canadian Office and Professional Employees Union, Local 378, expired on March 31, 2012. A new three-year collective agreement, expiring on March 31, 2015, was reached in March 2013.
The collective agreement between FortisBC Electric and the International Brotherhood of Electrical Workers ("IBEW"), Local 213, expired on January 31, 2013. IBEW, Local 213, represents employees in specified occupations in the areas of generation and transmission and distribution. The parties are currently engaged in collective bargaining.
CHANGES IN ACCOUNTING POLICIES
The new US GAAP accounting pronouncements that are applicable to, and were adopted by, Fortis, effective January 1, 2013, are described as follows:
Disclosures About Offsetting Assets and Liabilities
The Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 210, Balance Sheet - Disclosures About Offsetting Assets and Liabilities as outlined in Accounting Standards Updates ("ASU") No. 2011-11 and 2013-01. The amendments improve the transparency of the effect or potential effect of netting arrangements on a company's financial position by expanding the level of disclosures required by entities for such arrangements. The amended disclosures are intended to assist financial statement users in understanding significant quantitative differences between balance sheets prepared under US GAAP and International Financial Reporting Standards ("IFRS"). ASU No. 2013-01 limits the scope of the new offsetting disclosure requirements previously issued in ASU No. 2011-11 to certain derivative instruments, repurchase and reverse repurchase agreements, and securities borrowing and lending arrangements that are either offset on the balance sheet or subject to an enforceable master netting or similar arrangement. The above-noted amendments were applied retrospectively and did not materially impact the Corporation's interim consolidated financial statements for the three months ended March 31, 2013.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The Corporation adopted the amendments to ASC Topic 220, Other Comprehensive Income - Reporting of Amounts Out of Accumulated Other Comprehensive Income ("AOCI") as outlined in ASU No. 2013-02. The amendments improve the reporting of reclassifications out of AOCI and require entities to report, in one place, information about reclassifications out of AOCI and to present details of the reclassifications in the disclosure for changes in AOCI balances. The effect of the reclassification of significant items to net income in their entirety during the reporting period must be reported in the respective line items in the statement where net income is presented. The effect of items not reclassified to net income in their entirety during the reporting period are to be presented in the notes to the consolidated financial statements. 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, 2013.
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. Certain amounts are recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. In April 2013 Newfoundland Power received a decision related to the utility's cost of capital for rate-making purposes for 2013 through 2015, the cumulative impacts of which will be recorded in the second quarter of 2013, when the decision was received, with the impact related to the first quarter of 2013 determined to be immaterial. 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.
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 year-to-date 2013 from those disclosed in the 2012 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 effect on the Corporation's consolidated financial position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
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 proposed 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 proposed 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.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of Assessment from Canada Revenue Agency for additional taxes related to the taxation years 1999 through 2003. The exposure has been fully provided for in the consolidated financial statements. FHI is appealing these assessments.
In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia 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 interim unaudited 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 now 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. In addition, private landowners have filed separate writs and statements of claim dated August 19, 2005 and August 22, 2005 in relation to the same matter, which claims have now been settled. 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 interim unaudited consolidated financial statements.
The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which includes 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 $15 million. While FortisBC Electric has not been served, the utility has retained counsel and has notified its insurers. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the interim unaudited consolidated financial statements.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2011 through March 31, 2013. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. The timing of the recognition of certain assets, liabilities, revenue and expenses as a result of regulation may differ from that otherwise expected using US GAAP for non-regulated entities. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
Summary of Quarterly Results
(Unaudited) |
|
|
|
| |
Revenue |
Net Earnings
Attributable to
Common Equity
Shareholders |
Earnings per Common Share |
| Quarter Ended |
($ millions) |
($ millions) |
Basic ($) |
Diluted ($) |
| 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 |
| March 31, 2012 |
1,149 |
121 |
0.64 |
0.62 |
| December 31, 2011 |
1,034 |
82 |
0.44 |
0.43 |
| September 30, 2011 |
699 |
56 |
0.30 |
0.30 |
| June 30, 2011 |
846 |
57 |
0.32 |
0.32 |
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. Earnings for the first quarter of 2013 included an extraordinary gain of approximately $22 million after tax upon the settlement of expropriation matters associated with Exploits Partnership. Earnings for the first, second and third quarters of 2012 were reduced by approximately $4 million, $3 million and $0.5 million, respectively, associated with costs incurred related to the pending acquisition of CH Energy Group. During the second quarter of 2012, the FortisBC Energy companies and FortisAlberta received revenue requirements decisions, effective January 1, 2012, the cumulative impacts of which, where such impacts were different from those estimated, were recorded in the second quarter of 2012. Similarly, FortisBC Electric recorded the cumulative impacts of its rate decision, effective January 1, 2012, in the third quarter of 2012 when the decision was received. While not significant, the financial results from the third quarter ended September 30, 2012 reflected the acquisition of TCU in August 2012, financial results from the fourth quarter ended December 31, 2012 reflected the acquisition of the StationPark All Suite Hotel in October 2012 and financial results from the fourth quarter ended December 31, 2011 reflected the acquisition of the Hilton Suites Winnipeg Airport hotel in October 2011. Earnings for the third quarter ended September 30, 2011 included the $11 million after-tax termination fee paid to Fortis by Central Vermont Public Service Corporation ("CVPS").
March 2013/March 2012: Net earnings attributable to common equity shareholders were $151 million, or $0.79 per common share, for the first quarter of 2013 compared to earnings of $121 million, or $0.64 per common share, for the first quarter of 2012. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
December 2012/December 2011: Net earnings attributable to common equity shareholders were $87 million, or $0.46 per common share, for the fourth quarter of 2012 compared to earnings of $82 million, or $0.44 per common share, for the fourth quarter of 2011. The increase in earnings was primarily due to higher contribution from FortisAlberta, Other Canadian Regulated Electric Utilities and FortisBC Electric, partially offset by decreased non-regulated hydroelectric production in Belize associated with lower rainfall, increased corporate expenses and decreased earnings at the FortisBC Energy companies. Higher earnings at FortisAlberta were driven by rate base growth, net transmission revenue of $2 million recognized in the fourth quarter of 2012 and the rate revenue reduction accrual during the fourth quarter of 2011, reflecting the cumulative impact from January 1, 2011 of the decrease in the allowed ROE for 2011. At Other Canadian Regulated Electric Utilities, improved performance was mainly due to lower effective income taxes at Maritime Electric and the accrual of the cumulative return earned on FortisOntario's capital investment in smart meters. Increased earnings at FortisBC Electric were driven by rate base growth, lower-than-expected finance charges in 2012 and higher pole-attachment revenue, partially offset by the expiry of the PBR mechanism on December 31, 2011. The increase in corporate expenses was largely due to a $3 million non-recurring provision recognized in the fourth quarter of 2012 and lower effective income tax recoveries, partially offset by a foreign exchange gain of $1 million recognized in the fourth quarter of 2012, compared to a foreign exchange loss of $1 million recognized in the fourth quarter of 2011, and lower finance charges. At the FortisBC Energy companies, the decrease in earnings was mainly due to the timing of certain operating and maintenance expenses during 2012, lower capitalized AFUDC and lower-than-expected customer additions in 2012, partially offset by rate base growth, higher gas transportation volumes to industrial customers and lower effective income taxes.
September 2012/September 2011: Net earnings attributable to common equity shareholders were $45 million, or $0.24 per common share, for the third quarter of 2012 compared to earnings of $56 million, or $0.30 per common share, for the third quarter of 2011. Earnings for the third quarter of 2012 were reduced by $3.5 million related to foreign exchange and CH Energy Group acquisition-related expenses. Earnings for the third quarter of 2011 were favourably impacted by a one-time $11 million after-tax merger termination fee paid to Fortis by CVPS and $2.5 million of foreign exchange. Excluding the above impacts, higher earnings at FortisAlberta and FortisBC Electric for the quarter were partially offset by decreased non-regulated hydroelectric generation in Belize, due to lower rainfall, and a higher loss incurred at the FortisBC Energy companies. The improved performance at FortisAlberta was due to net transmission revenue of $3.5 million recognized in the third quarter of 2012, rate base growth and the timing of operating expenses during 2012, partially offset by a lower allowed ROE. At FortisBC Electric, improved performance was driven by rate base growth, higher pole-attachment revenue and lower-than-expected finance charges. The higher loss at the FortisBC Energy companies related to the unfavourable impact of the difference in the timing of recognition of revenue associated with seasonal gas consumption and certain increased regulator-approved expenses in 2012, lower capitalized AFUDC and lower-than-expected customer additions in 2012. The above items were partially offset by higher gas transportation volumes to industrial customers and the timing of certain operating and maintenance expenses during 2012.
June 2012/June 2011: Net earnings attributable to common equity shareholders were $62 million, or $0.33 per common share, for the second quarter of 2012 compared to earnings of $57 million, or $0.32 per common share, for the second quarter of 2011. The increase in earnings was mainly due to higher contribution from FortisAlberta, increased non-regulated hydroelectric production in Belize associated with higher rainfall, and higher earnings at Newfoundland Power, partially offset by higher corporate expenses and decreased earnings at the FortisBC Energy companies. Higher contribution from FortisAlberta related to rate base growth, net transmission revenue of $3 million recognized in the second quarter of 2012 and reduced depreciation as approved by the regulator, were partially offset by a lower allowed ROE. Higher earnings at Newfoundland Power were the result of lower effective income taxes and a higher allowed ROE. The cumulative impact of the increase in the regulator-approved allowed ROE, effective January 1, 2012, was recorded in the second quarter of 2012. The increase in corporate expenses was due to approximately $4 million ($3 million after tax) of costs incurred during the second quarter of 2012 related to the pending acquisition of CH Energy Group and a lower income tax recovery, partially offset by a foreign exchange gain of approximately $1.5 million recognized in the second quarter of 2012. Decreased earnings at the FortisBC Energy companies mainly related to lower-than-expected customer additions in 2012 and lower capitalized AFUDC, partially offset by higher gas transportation volumes to industrial customers. A 7% increase in the weighted average number of common shares outstanding quarter over quarter, largely associated with the issuance of common equity mid-2011, had the impact of tempering earnings per common share in the second quarter of 2012.
OUTLOOK
Over the five years 2013 through 2017, the Corporation's consolidated capital expenditure program, including expenditures at Central Hudson, is expected to total approximately $6 billion and will support continuing growth in earnings and dividends. Capital investment over that period is expected to allow utility rate base and hydroelectric generation investment to increase at a combined compound annual growth rate of approximately 6%.
Approval by the PSC of the Corporation's acquisition of CH Energy Group is the last significant regulatory matter required to close the transaction. While no assurance regarding a closing of the transaction can be given until an order is issued by the PSC, a final decision by the PSC and subsequent closing of the transaction is expected in June 2013. With the acquisition of CH Energy Group, the Corporation's regulated midyear rate base will increase to approximately $10 billion.
Fortis is focused on closing the CH Energy Group acquisition. The Corporation also remains disciplined and patient in its pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for its shareholders. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at May 6, 2013, the Corporation had issued and outstanding approximately 192.6 million common shares; 5.0 million First Preference Shares, Series C; 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; and 18.5 million Subscription 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 C and E, and Subscription Receipts were converted as at May 6, 2013 is as follows.
| Conversion of Securities into Common Shares (Unaudited) |
| As at May 6, 2013 |
Number of |
| |
Common Shares |
| Security |
(millions) |
| Stock Options |
5.2 |
| First Preference Shares, Series C |
3.8 |
| First Preference Shares, Series E |
6.0 |
| Subscription Receipts |
18.5 |
| Total |
33.5 |
Additional information, including the Fortis 2012 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, 2013 and 2012 |
| (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, |
|
| |
2013 |
|
2012 |
|
| |
|
|
|
|
|
|
| ASSETS |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Current assets |
|
|
|
|
|
|
| Cash and cash equivalents |
$ |
168 |
|
$ |
154 |
|
| Accounts receivable |
|
675 |
|
|
587 |
|
| Prepaid expenses |
|
15 |
|
|
18 |
|
| Inventories |
|
78 |
|
|
133 |
|
| Regulatory assets (Note 3) |
|
129 |
|
|
185 |
|
| Deferred income taxes |
|
22 |
|
|
16 |
|
| |
|
1,087 |
|
|
1,093 |
|
| |
|
|
|
|
|
|
| Other assets |
|
206 |
|
|
200 |
|
| Regulatory assets (Note 3) |
|
1,544 |
|
|
1,515 |
|
| Utility capital assets |
|
9,779 |
|
|
9,623 |
|
| Income producing properties |
|
635 |
|
|
626 |
|
| Intangible assets |
|
319 |
|
|
325 |
|
| Goodwill (Note 13) |
|
1,585 |
|
|
1,568 |
|
| |
|
|
|
|
|
|
| |
$ |
15,155 |
|
$ |
14,950 |
|
| |
|
|
|
|
|
|
| LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
| |
|
|
|
|
|
|
| Current liabilities |
|
|
|
|
|
|
| Short-term borrowings (Note 18) |
$ |
89 |
|
$ |
136 |
|
| Accounts payable and other current liabilities |
|
886 |
|
|
966 |
|
| Regulatory liabilities (Note 3) |
|
110 |
|
|
72 |
|
| Current installments of long-term debt |
|
81 |
|
|
117 |
|
| Current installments of capital lease and finance obligations |
|
7 |
|
|
7 |
|
| Deferred income taxes |
|
8 |
|
|
10 |
|
| |
|
1,181 |
|
|
1,308 |
|
| |
|
|
|
|
|
|
| Other liabilities |
|
635 |
|
|
638 |
|
| Regulatory liabilities (Note 3) |
|
696 |
|
|
681 |
|
| Deferred income taxes |
|
721 |
|
|
702 |
|
| Long-term debt |
|
5,933 |
|
|
5,783 |
|
| Capital lease and finance obligations |
|
434 |
|
|
428 |
|
| |
|
9,600 |
|
|
9,540 |
|
| |
|
|
|
|
|
|
| Shareholders' equity |
|
|
|
|
|
|
| Common shares (1)(Note 4) |
|
3,149 |
|
|
3,121 |
|
| Preference shares |
|
1,108 |
|
|
1,108 |
|
| Additional paid-in capital |
|
15 |
|
|
15 |
|
| Accumulated other comprehensive loss |
|
(93 |
) |
|
(96 |
) |
| Retained earnings |
|
1,043 |
|
|
952 |
|
| |
|
5,222 |
|
|
5,100 |
|
| Non-controlling interests (Note 5) |
|
333 |
|
|
310 |
|
| |
|
5,555 |
|
|
5,410 |
|
| |
|
|
|
|
|
|
| |
$ |
15,155 |
|
$ |
14,950 |
|
| |
|
| (1) |
no par value: unlimited authorized shares; 192.5 million and 191.6 million issued and outstanding as at March 31, 2013 and December 31, 2012, respectively |
| |
|
| |
Commitments and Contingent Liabilities (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 |
|
| |
2013 |
2012 |
|
| |
|
|
|
|
|
| Revenue |
$ |
1,113 |
$ |
1,149 |
|
| |
|
|
|
|
|
| Expenses |
|
|
|
|
|
| |
Energy supply costs |
|
505 |
|
566 |
|
| |
Operating |
|
221 |
|
214 |
|
| |
Depreciation and amortization |
|
129 |
|
119 |
|
| |
|
855 |
|
899 |
|
| |
|
|
|
|
|
| Operating income |
|
258 |
|
250 |
|
| |
|
|
|
|
|
| Other income (expenses), net (Note 8) |
|
6 |
|
(3 |
) |
| Finance charges (Note 9) |
|
89 |
|
91 |
|
| |
|
|
|
|
|
| Earnings before income taxes and extraordinary item |
|
175 |
|
156 |
|
| |
|
|
|
|
|
| Income taxes (Note 10) |
|
30 |
|
23 |
|
| |
|
|
|
|
|
| Earnings before extraordinary item |
|
145 |
|
133 |
|
| |
|
|
|
|
|
| Extraordinary gain, net of tax (Note 11) |
|
22 |
|
- |
|
| |
|
|
|
|
|
| Net earnings |
$ |
167 |
$ |
133 |
|
| |
|
|
|
|
|
| Net earnings attributable to: |
|
|
|
|
|
| |
Non-controlling interests |
$ |
2 |
$ |
1 |
|
| |
Preference equity shareholders |
|
14 |
|
11 |
|
| |
Common equity shareholders |
|
151 |
|
121 |
|
| |
$ |
167 |
$ |
133 |
|
| |
|
|
|
|
|
| Earnings per common share before extraordinary item (Note 12) |
|
|
|
|
|
| |
Basic |
$ |
0.67 |
$ |
0.64 |
|
| |
Diluted |
$ |
0.66 |
$ |
0.62 |
|
| Earnings per common share (Note 12) |
|
|
|
|
|
| |
Basic |
$ |
0.79 |
$ |
0.64 |
|
| |
Diluted |
$ |
0.76 |
$ |
0.62 |
|
| |
|
|
|
|
|
| |
| 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 |
|
| |
2013 |
2012 |
|
| |
|
|
|
|
|
| Net earnings |
$ |
167 |
$ |
133 |
|
| |
|
|
|
|
|
| Other comprehensive income (loss) |
|
|
|
|
|
| Unrealized foreign currency translation gains (losses), net of hedging activities and tax |
|
2 |
|
(2 |
) |
| Unrealized employee future benefits gains, net of tax |
|
1 |
|
1 |
|
| |
|
3 |
|
(1 |
) |
| |
|
|
|
|
|
| Comprehensive income |
$ |
170 |
$ |
132 |
|
| |
|
|
|
|
|
| Comprehensive income attributable to: |
|
|
|
|
|
| |
Non-controlling interests |
$ |
2 |
$ |
1 |
|
| |
Preference equity shareholders |
|
14 |
|
11 |
|
| |
Common equity shareholders |
|
154 |
|
120 |
|
| |
$ |
170 |
$ |
132 |
|
| |
| 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 |
|
| |
2013 |
|
2012 |
|
| |
|
|
|
|
|
|
| Operating activities |
|
|
|
|
|
|
| Net earnings |
$ |
167 |
|
$ |
133 |
|
| Adjustments to reconcile net earnings to net cash provided by operating activities: |
|
|
|
|
|
|
| |
Depreciation - utility capital assets and income producing properties |
|
113 |
|
|
107 |
|
| |
Amortization - intangible assets |
|
12 |
|
|
11 |
|
| |
Amortization - other |
|
4 |
|
|
1 |
|
| |
Deferred income taxes |
|
(11 |
) |
|
5 |
|
| |
Accrued employee future benefits |
|
(1 |
) |
|
4 |
|
| |
Equity component of allowance for funds used construction (Note 8) |
|
(3 |
) |
|
(2 |
) |
| |
Other |
|
(10 |
) |
|
(14 |
) |
| Change in long-term regulatory assets and liabilities |
|
(9 |
) |
|
4 |
|
| Change in non-cash operating working capital (Note 15) |
|
18 |
|
|
79 |
|
| |
|
280 |
|
|
328 |
|
| |
|
|
|
|
|
|
| Investing activities |
|
|
|
|
|
|
| Change in other assets and other liabilities |
|
5 |
|
|
4 |
|
| Capital expenditures - utility capital assets |
|
(230 |
) |
|
(211 |
) |
| Capital expenditures - income producing properties |
|
(13 |
) |
|
(5 |
) |
| Capital expenditures - intangible assets |
|
(7 |
) |
|
(13 |
) |
| Contributions in aid of construction |
|
10 |
|
|
14 |
|
| Proceeds on sale of utility capital assets and income producing properties |
|
1 |
|
|
- |
|
| Business acquisition, net of cash acquired (Note 13) |
|
(55 |
) |
|
- |
|
| |
|
(289 |
) |
|
(211 |
) |
| |
|
|
|
|
|
|
| Financing activities |
|
|
|
|
|
|
| Change in short-term borrowings |
|
(48 |
) |
|
(83 |
) |
| Repayments of long-term debt and capital lease and finance obligations |
|
(40 |
) |
|
(4 |
) |
| Net borrowings under committed credit facilities |
|
136 |
|
|
7 |
|
| Advances from non-controlling interests |
|
22 |
|
|
41 |
|
| Issue of common shares, net of costs and dividends reinvested |
|
10 |
|
|
2 |
|
| Dividends |
|
|
|
|
|
|
| |
Common shares, net of dividends reinvested |
|
(41 |
) |
|
(44 |
) |
| |
Preference shares |
|
(14 |
) |
|
(11 |
) |
| |
Subsidiary dividends paid to non-controlling interests |
|
(2 |
) |
|
(2 |
) |
| |
|
23 |
|
|
(94 |
) |
| |
|
|
|
|
|
|
| Change in cash and cash equivalents |
|
14 |
|
|
23 |
|
| |
|
|
|
|
|
|
| Cash and cash equivalents, beginning of period |
|
154 |
|
|
87 |
|
| |
|
|
|
|
|
|
| Cash and cash equivalents, end of period |
$ |
168 |
|
$ |
110 |
|
| |
| 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 4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at January 1, 2012 |
$ |
3,036 |
$ |
912 |
$ |
14 |
|
$ |
(95 |
) |
$ |
868 |
|
$ |
208 |
|
$ |
4,943 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net earnings |
|
- |
|
- |
|
- |
|
|
- |
|
|
132 |
|
|
1 |
|
|
133 |
|
| Other comprehensive loss |
|
- |
|
- |
|
- |
|
|
(1 |
) |
|
- |
|
|
- |
|
|
(1 |
) |
| Common share issues |
|
14 |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
14 |
|
| Stock-based compensation |
|
- |
|
- |
|
1 |
|
|
- |
|
|
- |
|
|
- |
|
|
1 |
|
| Advances from non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
41 |
|
|
41 |
|
| Foreign currency translation impacts |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
(2 |
) |
|
(2 |
) |
| Subsidiary dividends paid to non-controlling interests |
|
- |
|
- |
|
- |
|
|
- |
|
|
- |
|
|
(2 |
) |
|
(2 |
) |
| Dividends declared on common shares ($0.30 per share) |
|
- |
|
- |
|
- |
|
|
- |
|
|
(57 |
) |
|
- |
|
|
(57 |
) |
| Dividends declared on preference shares |
|
- |
|
- |
|
- |
|
|
- |
|
|
(11 |
) |
|
- |
|
|
(11 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| As at March 31, 2012 |
$ |
3,050 |
$ |
912 |
$ |
15 |
|
$ |
(96 |
) |
$ |
932 |
|
$ |
246 |
|
$ |
5,059 |
|
| |
| See accompanying Notes to Interim Consolidated Financial Statements |
| |
| |
| |
| FORTIS INC. |
| NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS |
| For the three months ended March 31, 2013 and 2012 (unless otherwise stated) |
| (Unaudited) |
1. DESCRIPTION OF THE BUSINESS
NATURE OF OPERATIONS
Fortis Inc. ("Fortis" or the "Corporation") is principally an international 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 assets, and commercial office and retail space and hotels, 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 autonomously, 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 2012 annual audited consolidated financial statements.
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities in Canada and the Caribbean are as follows:
- Regulated Gas Utilities - Canadian: Includes the FortisBC Energy companies, comprised of FortisBC Energy Inc., FortisBC Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc.
- Regulated Electric Utilities - Canadian: Comprised of FortisAlberta; FortisBC Electric; Newfoundland Power; and Other Canadian Electric Utilities, which includes 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 ownership interest; three small wholly owned utilities in the Turks and Caicos Islands, which include FortisTCI Limited, Atlantic Equipment & Power (Turks and Caicos) Ltd. and Turks and Caicos Utilities Limited, acquired in August 2012, (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. Effective March 2013 the Corporation and the Government of Newfoundland and Labrador ("Government") 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 Exploits River Hydro Partnership ("Exploits Partnership") in which Fortis holds an indirect 51% interest through Fortis Properties (Note 11).
NON-REGULATED - 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.
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 Fortis net corporate expenses and the net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related activities. Also included in the Corporate and Other segment are the financial results of CustomerWorks Limited Partnership ("CWLP") and FortisBC Alternative Energy Services Inc. ("FAES"). CWLP is a non-regulated shared-services business in which FHI holds a 30% interest. CWLP provides billing and customer care services to utilities, municipalities and certain energy companies. CWLP's financial results are recorded using the equity method of accounting. FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.
PENDING ACQUISITION
In February 2012 Fortis announced that it had entered into an agreement to acquire CH Energy Group, Inc. ("CH Energy Group") for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation, is a regulated transmission and distribution utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The transaction received CH Energy Group shareholder approval in June 2012 and regulatory approval from the Federal Energy Regulatory Commission and the Committee on Foreign Investment in the United States in July 2012. In addition, the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in October 2012, satisfying another condition necessary for consummation of the transaction.
Approval by the New York State Public Service Commission ("PSC") of the Corporation's acquisition of CH Energy Group is the last significant regulatory matter required to close the transaction. A Settlement Agreement among Fortis, CH Energy Group, PSC staff, registered interveners and other parties was filed with the PSC in January 2013. The parties to the Settlement Agreement have concluded that, based on the terms of the Settlement Agreement, the acquisition is in the public interest and have recommended approval by the PSC. A Recommended Decision issued on May 3, 2013 by administrative law judges in connection with the acquisition asserts that without modification of the Settlement Agreement, the benefits of the acquisition are outweighed by perceived detriments remaining after mitigation. The Recommended Decision is an advisory opinion that will be considered by the PSC in determining whether to approve the acquisition. While no assurance regarding a closing of the transaction can be given until an order is issued by the PSC, a final decision by the PSC and subsequent closing of the transaction is expected in June 2013.
Unless extended by agreement of both parties, the agreement and plan of merger between Fortis and CH Energy Group expires August 20, 2013 (Notes 8, 19 and 21).
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 2012 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 utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. In April 2013 Newfoundland Power received a decision related to the utility's cost of capital for 2013 through 2015, the cumulative impacts of which will be recorded in the second quarter of 2013, when the decision was received, with the impact related to the first quarter of 2013 determined to be immaterial. 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 reported in earnings in the period in which they become known.
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, 2013.
An evaluation of subsequent events through to May 6, 2013, 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, 2013.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements include 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 2012 annual audited consolidated financial statements, except as described below.
NEW ACCOUNTING POLICIES
Disclosures About Offsetting Assets and Liabilities
Effective January 1, 2013, the Corporation adopted the amendments to Accounting Standards Codification ("ASC") Topic 210, Balance Sheet - Disclosures About Offsetting Assets and Liabilities as outlined in Accounting Standards Updates ("ASU") No. 2011-11 and 2013-01. The amendments improve the transparency of the effect or potential effect of netting arrangements on a company's financial position by expanding the level of disclosures required by entities for such arrangements. The amended disclosures are intended to assist financial statement users in understanding significant quantitative differences between balance sheets prepared under US GAAP and International Financial Reporting Standards ("IFRS"). ASU No. 2013-01 limits the scope of the new offsetting disclosure requirements previously issued in ASU No. 2011-11 to certain derivative instruments, repurchase and reverse repurchase agreements, and securities borrowing and lending arrangements that are either offset on the balance sheet or subject to an enforceable master netting or similar arrangement. The above-noted amendments were applied retrospectively and did not materially impact the Corporation's interim consolidated financial statements for the three months ended March 31, 2013.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Effective January 1, 2013, the Corporation adopted the amendments to ASC Topic 220, Other Comprehensive Income - Reporting of Amounts Out of Accumulated Other Comprehensive Income ("AOCI") as outlined in ASU No. 2013-02. The amendments improve the reporting of reclassifications out of AOCI and require entities to report, in one place, information about reclassifications out of AOCI and to present details of the reclassifications in the disclosure for changes in AOCI balances. The effect of the reclassification of significant items to net income in their entirety during the reporting period must be reported in the respective line items in the statement where net income is presented. The effect of items not reclassified to net income in their entirety during the reporting period are to be presented in the notes to the consolidated financial statements. The amendments were applied by the Corporation prospectively commencing on January 1, 2013 and did not materially impact the Corporation's interim consolidated financial statements for the three months ended March 31, 2013.
3. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. A detailed description of the nature of the Corporation's regulatory assets and liabilities is provided in Note 7 to the Corporation's 2012 annual audited consolidated financial statements.
| |
As at |
|
| |
March 31, |
|
December 31, |
|
| ($ millions) |
2013 |
|
2012 |
|
| Regulatory assets |
|
|
|
|
| Deferred income taxes |
727 |
|
713 |
|
| Employee future benefits |
492 |
|
498 |
|
| Deferred lease costs - FortisBC Electric |
85 |
|
77 |
|
| Rate stabilization accounts - electric utilities |
62 |
|
57 |
|
| Deferred energy management costs |
53 |
|
50 |
|
| Deferred operating overhead costs |
35 |
|
32 |
|
| Deferred net losses on disposal of utility capital assets and intangible assets |
32 |
|
27 |
|
| Rate stabilization accounts - FortisBC Energy companies |
29 |
|
48 |
|
| Customer Care Enhancement Project cost deferral |
23 |
|
24 |
|
| Income taxes recoverable on other post-employment benefit ("OPEB") plans |
23 |
|
23 |
|
| Alternative energy projects cost deferral |
21 |
|
18 |
|
| Whistler pipeline contribution deferral |
13 |
|
14 |
|
| Deferred development costs for capital projects |
10 |
|
10 |
|
| Deferred costs - smart meters |
6 |
|
9 |
|
| Replacement energy deferral - Point Lepreau (1) |
- |
|
47 |
|
| Other regulatory assets |
62 |
|
53 |
|
| Total regulatory assets |
1,673 |
|
1,700 |
|
| Less: current portion |
(129 |
) |
(185 |
) |
| Long-term regulatory assets |
1,544 |
|
1,515 |
|
| |
|
| (1) |
In March 2013 Maritime Electric received proceeds of approximately $47 million from the Government of Prince Edward Island upon its assumption of the utility's regulatory asset associated with the deferral of certain incremental replacement energy costs during the refurbishment of the New Brunswick Power Point Lepreau nuclear generating station. |
| |
|
| |
|
| |
|
| |
As at |
|
| |
March 31, |
|
December 31, |
|
| ($ millions) |
2013 |
|
2012 |
|
| Regulatory liabilities |
|
|
|
|
| Non-asset retirement obligation removal cost provision |
494 |
|
486 |
|
| Rate stabilization accounts - FortisBC Energy companies |
133 |
|
117 |
|
| Alberta Electric System Operator charges deferral |
71 |
|
44 |
|
| Rate stabilization accounts - electric utilities |
44 |
|
46 |
|
| Deferred income taxes |
11 |
|
12 |
|
| Deferred interest |
9 |
|
9 |
|
| Meter reading and customer service variance deferral |
9 |
|
6 |
|
| Income tax variance deferral |
3 |
|
7 |
|
| Other regulatory liabilities |
32 |
|
26 |
|
| Total regulatory liabilities |
806 |
|
753 |
|
| Less: current portion |
(110 |
) |
(72 |
) |
| Long-term regulatory liabilities |
696 |
|
681 |
|
4. COMMON SHARES
| Common shares issued during the period were as follows: |
| |
Quarter Ended |
| |
March 31, 2013 |
| |
Number of |
|
| |
Shares |
Amount |
| |
(in thousands) |
($ millions) |
| Balance, beginning of period |
191,566 |
3,121 |
| |
Dividend Reinvestment Plan |
563 |
19 |
| |
Consumer Share Purchase Plan |
9 |
- |
| |
Employee Share Purchase Plan |
146 |
5 |
| |
Stock Option Plans |
192 |
4 |
| Balance, end of period |
192,476 |
3,149 |
As at March 31, 2013, Fortis had 18.5 million Subscription Receipts outstanding, which were issued by the Corporation in June 2012 to finance a portion of the pending acquisition of CH Energy Group (Note 1). The Subscription Receipts began trading on the Toronto Stock Exchange on June 27, 2012 under the symbol "FTS.R".
Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the release conditions, and without payment of additional consideration, one common share of Fortis and a cash payment equal to the dividends declared on Fortis common shares during the period from June 27, 2012 to the date of issuance of the common shares in respect of the Subscription Receipts to holders of record (Note 19).
5. NON-CONTROLLING INTERESTS
| |
As at |
| |
March 31, |
December 31, |
| ($ millions) |
2013 |
2012 |
| Waneta Expansion Limited Partnership ("Waneta Partnership") |
242 |
220 |
| Caribbean Utilities |
72 |
71 |
| Mount Hayes Limited Partnership |
12 |
12 |
| Preference shares of Newfoundland Power |
7 |
7 |
| |
333 |
310 |
6. STOCK-BASED COMPENSATION PLANS
In January 2013 8,497 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.
In March 2013 66,978 Performance Share Units ("PSUs") were paid out to the President and Chief Executive Officer ("CEO") of the Corporation at $33.59 per PSU, for a total of approximately $2 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2010 and the President and CEO satisfying the payment requirements, as determined by the Human Resource Committee of the Board of Directors of Fortis.
In March 2013 the Corporation granted 807,600 options to purchase common shares under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant of $33.58. 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 $3.91 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 (%) |
3.78 |
| Expected volatility (%) |
21.4 |
| Risk-free interest rate (%) |
1.31 |
| Weighted average expected life (years) |
5.3 |
For the three months ended March 31, 2013, stock-based compensation expense of approximately $1 million was recognized ($1 million for the three months ended March 31, 2012).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group registered retirement savings plans, for employees. The Corporation and certain subsidiaries also offer OPEB plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.
| |
Quarter Ended March 31 |
|
| |
Defined Benefit |
|
|
|
| |
Pension Plans |
|
OPEB Plans |
|
| ($ millions) |
2013 |
|
2012 |
|
2013 |
|
2012 |
|
| Components of net benefit cost: |
|
|
|
|
|
|
|
|
| Service costs |
8 |
|
7 |
|
2 |
|
2 |
|
| Interest costs |
12 |
|
12 |
|
3 |
|
3 |
|
| Expected return on plan assets |
(13 |
) |
(12 |
) |
- |
|
- |
|
| Amortization of actuarial losses |
7 |
|
6 |
|
2 |
|
1 |
|
| Amortization of past service credits/plan amendments |
- |
|
- |
|
(1 |
) |
(1 |
) |
| Regulatory adjustments |
(3 |
) |
(1 |
) |
- |
|
1 |
|
| Net benefit cost |
11 |
|
12 |
|
6 |
|
6 |
|
For the three months ended March 31, 2013, the Corporation expensed $4 million ($4 million for the three months ended March 31, 2012) related to defined contribution pension plans.
8. OTHER INCOME (EXPENSES), NET
| |
Quarter Ended |
|
| |
March 31 |
|
| ($ millions) |
2013 |
2012 |
|
| Equity component of allowance for funds used during construction ("AFUDC") |
3 |
2 |
|
| Net foreign exchange gain (loss) |
2 |
(2 |
) |
| Interest income |
1 |
1 |
|
| Acquisition-related expenses |
- |
(4 |
) |
| |
6 |
(3 |
) |
The foreign exchange gain for the three months ended March 31, 2013 comprised approximately $2 million 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). For the three months ended March 31, 2012 a foreign exchange loss of approximately $1.5 million was recognized on the translation into Canadian dollars of the above-noted long-term other asset.
The acquisition-related expenses are associated with the pending acquisition of CH Energy Group (Notes 1, 19 and 21).
9. FINANCE CHARGES
| |
|
Quarter Ended |
|
| |
|
March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
| Interest |
- Long-term debt and capital lease and finance obligations |
94 |
|
94 |
|
| |
- Short-term borrowings |
2 |
|
1 |
|
| Debt component of AFUDC |
(7 |
) |
(4 |
) |
| |
|
89 |
|
91 |
|
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) |
2013 |
|
2012 |
|
| Combined Canadian federal and provincial statutory income tax rate |
29.0 |
% |
29.0 |
% |
| Statutory income tax rate applied to earnings before income taxes |
51 |
|
45 |
|
| Difference in Canadian provincial statutory rates applicable to subsidiaries in different Canadian jurisdictions |
(6 |
) |
(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 |
(16 |
) |
(15 |
) |
| Difference between capital cost allowance and amounts claimed for accounting purposes |
(2 |
) |
3 |
|
| Non-deductible expenses |
1 |
|
- |
|
| Difference between enacted and substantively enacted income tax rates |
|
|
|
|
| associated with Part VI.1 tax |
2 |
|
- |
|
| Difference between employee future benefits paid and amounts expensed for accounting purposes |
1 |
|
- |
|
| Other |
1 |
|
(2 |
) |
| Income taxes |
30 |
|
23 |
|
| Effective income tax rate |
17.1 |
% |
14.7 |
% |
As at March 31, 2013, the Corporation had approximately $41 million (December 31, 2012 - $73 million) in non-capital and capital loss carryforwards, of which $13 million (December 31, 2012 - $13 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2013 and 2033.
11. EXTRAORDINARY GAIN, NET OF TAX
Effective March 2013 Fortis and the Government 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 Exploits Partnership in which Fortis holds an indirect 51% interest through Fortis Properties. The settlement of expropriation matters resulted in the recognition of an extraordinary gain of approximately $25 million ($22 million after tax) in the first quarter of 2013.
12. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS were as follows:
| |
Quarter Ended March 31 |
| |
2013 |
|
Earnings
to Common
Shareholders
Before
Extraordinary
Item
($ millions) |
Extraordinary
Gain
($ millions) |
Earnings
to Common
Shareholders
($ millions) |
Weighted
Average
Shares
(millions) |
EPS
Before
Extraordinary
Item |
EPS
Extraordinary
Gain |
EPS |
| 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 |
| |
|
| |
Quarter Ended March 31 |
| |
2012 |
| |
Earnings
to Common
Shareholders
Before
Extraordinary
Item
($ millions) |
Extraordinary
Gain
($ millions) |
Earnings
to Common
Shareholders
($ millions) |
Weighted
Average
Shares
(millions) |
EPS
Before
Extraordinary
Item |
EPS
Extraordinary
Gain |
EPS |
| Basic EPS |
121 |
- |
121 |
189.0 |
$ 0.64 |
- |
$ 0.64 |
| Effect of potential dilutive |
|
|
|
|
|
|
|
| securities: |
|
|
|
|
|
|
|
| |
Stock Options |
- |
- |
- |
1.0 |
|
|
|
| |
Preference Shares |
4 |
- |
4 |
10.3 |
|
|
|
| Diluted EPS |
125 |
- |
125 |
200.3 |
$ 0.62 |
- |
$ 0.62 |
13. BUSINESS ACQUISITION
In March 2013 FortisBC Electric acquired the City of Kelowna's (the "City's") electrical utility assets for approximately $55 million, which now allows FortisBC Electric to directly serve some 15,000 customers formerly served by the City. FortisBC Electric had provided the City with electricity under a wholesale tariff and had operated and maintained the City's electrical utility assets under contract since 2000.
The acquisition was approved by the British Columbia Utilities Commission in March 2013 and allowed for approximately $38 million of the purchase price to be included in FortisBC Electric's rate base. Based on this regulatory decision, the book value of the assets acquired has been assigned as fair value in the preliminary purchase price allocation. FortisBC Electric is regulated under cost of service and the determination of revenue and earnings is based on a regulated rate of return that is applied to historic values, which do not change with a change of ownership. Therefore, fair market value approximates book value and no fair market value adjustments were recorded for the assets acquired because all of the economic benefits and obligations associated with them beyond regulated rates of return accrue to the customers.
The following table summarizes the preliminary allocation of the purchase price to the assets acquired as at the date of acquisition based on their fair values.
| ($ millions) |
|
| Fair value assigned to assets: |
|
| Utility capital assets |
38 |
| Long-term deferred income tax asset |
3 |
| Goodwill |
14 |
| |
55 |
The acquisition, which qualifies as a business combination, has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing in March 2013.
14. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| |
REGULATED |
|
NON-REGULATED |
|
|
|
|
|
| |
Gas Utilities |
|
Electric Utilities |
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
March 31, 2013
($ millions) |
FortisBC
Energy
Companies
-
Canadian |
|
Fortis
Alberta |
|
FortisBC
Electric |
|
New-
found-
land
Power |
|
Other
Canadian |
|
Total
Electric
Canadian |
|
Electric
Caribbean |
|
Fortis
Generation |
|
Fortis
Properties |
|
Corporate
and Other |
|
Inter-
segment
eliminations |
|
Consolidated |
|
| 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, 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) before extraordinary item |
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 |
|
758 |
|
780 |
|
678 |
|
514 |
|
(460 |
) |
13,570 |
|
| Total assets |
5,521 |
|
3,033 |
|
1,993 |
|
1,419 |
|
776 |
|
7,221 |
|
901(1) |
|
780 |
|
678 |
|
514 |
|
(460 |
) |
15,155 |
|
| Gross capital expenditures |
38 |
|
95 |
|
17 |
|
15 |
|
13 |
|
140 |
|
11 |
|
48 |
|
13 |
|
- |
|
- |
|
250 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Quarter Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| March 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ($ millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Revenue |
548 |
|
108 |
|
87 |
|
192 |
|
91 |
|
478 |
|
63 |
|
9 |
|
52 |
|
6 |
|
(7 |
) |
1,149 |
|
| Energy supply costs |
302 |
|
- |
|
25 |
|
142 |
|
58 |
|
225 |
|
40 |
|
- |
|
- |
|
- |
|
(1 |
) |
566 |
|
| Operating expenses |
70 |
|
39 |
|
21 |
|
20 |
|
12 |
|
92 |
|
8 |
|
3 |
|
40 |
|
3 |
|
(2 |
) |
214 |
|
| Depreciation and amortization |
40 |
|
35 |
|
12 |
|
11 |
|
7 |
|
65 |
|
7 |
|
1 |
|
5 |
|
1 |
|
- |
|
119 |
|
| Operating income |
136 |
|
34 |
|
29 |
|
19 |
|
14 |
|
96 |
|
8 |
|
5 |
|
7 |
|
2 |
|
(4 |
) |
250 |
|
| Other income (expenses), net |
- |
|
2 |
|
- |
|
- |
|
- |
|
2 |
|
- |
|
1 |
|
- |
|
(5 |
) |
(1 |
) |
(3 |
) |
| Finance charges |
35 |
|
15 |
|
10 |
|
9 |
|
5 |
|
39 |
|
4 |
|
1 |
|
6 |
|
11 |
|
(5 |
) |
91 |
|
| Income tax expense (recovery) |
19 |
|
- |
|
3 |
|
3 |
|
2 |
|
8 |
|
- |
|
- |
|
- |
|
(4 |
) |
- |
|
23 |
|
| Net earnings (loss) |
82 |
|
21 |
|
16 |
|
7 |
|
7 |
|
51 |
|
4 |
|
5 |
|
1 |
|
(10 |
) |
- |
|
133 |
|
| Non-controlling interests |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
1 |
|
- |
|
- |
|
- |
|
- |
|
1 |
|
| Preference share dividends |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
11 |
|
- |
|
11 |
|
| Net earnings (loss) attributable to common equity shareholders |
82 |
|
21 |
|
16 |
|
7 |
|
7 |
|
51 |
|
3 |
|
5 |
|
1 |
|
(21 |
) |
- |
|
121 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Goodwill |
913 |
|
227 |
|
221 |
|
- |
|
63 |
|
511 |
|
139 |
|
- |
|
- |
|
- |
|
- |
|
1,563 |
|
| Identifiable assets |
4,586 |
|
2,506 |
|
1,677 |
|
1,324 |
|
690 |
|
6,197 |
|
708 |
|
612 |
|
612 |
|
462 |
|
(399 |
) |
12,778 |
|
| Total assets |
5,499 |
|
2,733 |
|
1,898 |
|
1,324 |
|
753 |
|
6,708 |
|
847(1) |
|
612 |
|
612 |
|
462 |
|
(399 |
) |
14,341 |
|
| Gross capital expenditures |
46 |
|
79 |
|
17 |
|
15 |
|
9 |
|
120 |
|
10 |
|
48 |
|
5 |
|
- |
|
- |
|
229 |
|
| |
|
| (1) |
Includes the Corporation's long-term other asset associated with its expropriated investment in Belize Electricity |
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 Fortis Properties; and (ii) finance charges on related party borrowings. The significant related party inter-segment transactions for the three months ended March 31, 2013 and 2012 were as follows:
| Significant Inter-Segment Transactions |
Quarter Ended |
| |
March 31 |
| ($ millions) |
2013 |
2012 |
| Sales from Newfoundland Power to Fortis Properties |
2 |
2 |
| Inter-segment finance charges on lending from: |
|
|
| |
Corporate to Regulated Electric Utilities - Caribbean |
1 |
1 |
| |
Corporate to Fortis Properties |
5 |
4 |
| |
|
|
| The significant inter-segment asset balances were as follows: |
| |
| |
As at March 31 |
| ($ millions) |
2013 |
2012 |
| Inter-segment lending from: |
|
|
| |
Fortis Generation to Other Canadian Electric Utilities |
20 |
20 |
| |
Corporate to Regulated Electric Utilities - Caribbean |
86 |
76 |
| |
Corporate to Fortis Generation |
6 |
20 |
| |
Corporate to Fortis Properties |
319 |
257 |
| Other inter-segment assets |
29 |
26 |
| Total inter-segment eliminations |
460 |
399 |
15. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| |
Quarter Ended |
|
| |
March 31 |
|
| ($ millions) |
2013 |
|
2012 |
|
| |
|
|
|
|
| Change in non-cash operating working capital: |
|
|
|
|
| Accounts receivable |
(79 |
) |
(59 |
) |
| Prepaid expenses |
3 |
|
2 |
|
| Regulatory assets - current portion |
34 |
|
43 |
|
| Inventories |
55 |
|
58 |
|
| Accounts payable and other current liabilities |
(30 |
) |
9 |
|
| Regulatory liabilities - current portion |
35 |
|
26 |
|
| |
18 |
|
79 |
|
| |
|
|
|
|
| Non-cash investing and financing activities: |
|
|
|
|
| Common share dividends reinvested |
19 |
|
13 |
|
| Additions to utility capital assets, income producing properties and intangible assets included in current liabilities |
70 |
|
105 |
|
| Contributions in aid of construction included in current assets |
20 |
|
11 |
|
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, 2013, the Corporation's derivative contracts consisted of fuel option contracts, natural gas swap and option contracts, and gas purchase contract premiums. The fuel option contracts are held by Caribbean Utilities and the remaining derivative instruments are held by the FortisBC Energy companies.
Volume of Derivative Activity
As at March 31, 2013, the following notional volumes related to fuel option contracts and natural gas commodity derivatives that are expected to be settled are outlined below.
| |
2013 |
2014 |
| Fuel option contracts (millions of imperial gallons) |
13 |
- |
| Gas swaps and options (petajoules) |
12 |
7 |
| Gas purchase contract premiums (petajoules) |
68 |
12 |
Presentation of Derivative Instruments in the Consolidated Financial Statements
In the Corporation's consolidated balance sheets, 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) |
2013 |
2012 |
| Gross derivatives balance (1) |
36 |
60 |
| Netting (2) |
- |
- |
| Cash collateral |
- |
- |
| Total derivative balances (3) |
36 |
60 |
| |
|
| (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 $36 million on commodity risk-related derivative instruments as at March 31, 2013 were recognized in current regulatory assets (December 31, 2012 - $60 million), which would otherwise be recognized on the consolidated statement of comprehensive income and in accumulated other comprehensive loss. |
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 which 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 certain long-term debt as noted.
| |
As at |
|
| Asset (Liability) |
March 31, 2013 |
|
December 31, 2012 |
|
| |
Carrying |
|
Estimated |
|
Carrying |
|
Estimated |
|
| ($ millions) |
Value |
|
Fair Value |
|
Value |
|
Fair Value |
|
| Long-term other asset - Belize Electricity (1) |
106 |
|
n/a (2) |
|
104 |
|
n/a (2) |
|
| Long-term debt, including current portion (3) |
(6,014 |
) |
(7,332 |
) |
(5,900 |
) |
(7,338 |
) |
| Waneta Partnership promissory note (4) |
(48 |
) |
(52 |
) |
(47 |
) |
(51 |
) |
| Fuel option contracts (5) |
- |
|
- |
|
(1 |
) |
(1 |
) |
| Natural gas commodity derivatives: (5) |
|
|
|
|
|
|
|
|
| |
Swaps and options |
(33 |
) |
(33 |
) |
(51 |
) |
(51 |
) |
| |
Gas purchase contract premiums |
(3 |
) |
(3 |
) |
(8 |
) |
(8 |
) |
| |
|
| (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) |
The Corporation's $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term of $266 million (December 31, 2012 - $150 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs. |
| |
|
| (4) |
Included in long-term other liabilities on the consolidated balance sheet |
| |
|
| (5) |
The fair values of the derivatives were recorded in accounts payable and other current liabilities as at March 31, 2013 and December 31, 2012. The fair value of the fuel option contracts as at March 31, 2013 was less than $1 million. |
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) by 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 fuel option contracts are used by Caribbean Utilities to reduce the impact of volatility in fuel prices on customer rates, as approved by the regulator under the Company's Fuel Price Volatility Management Program. The fair value of the fuel option contracts reflects only the value of the heating oil derivative and not the offsetting change in the value of the underlying future purchases of heating oil and was calculated using published market prices for heating oil or similar commodities where appropriate. The fuel option contracts mature in April and October 2013. Approximately 70% of the Company's annual diesel fuel requirements are under fuel hedging arrangements.
The natural gas commodity derivatives are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts at the FortisBC Energy companies have floating, rather than fixed, prices. The fair value of the natural gas commodity derivatives was calculated using the present value of cash flows based on market prices and forward curves for the commodity cost of natural gas.
The fair values of the fuel option contracts and natural gas commodity 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, 2013, none of the fuel option contracts or natural gas commodity derivatives were designated as hedges of fuel purchases or 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, 2013, 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 approximately $3 million by obtaining from the retailers either a cash deposit, bond, letter of credit or an investment-grade credit rating from a major rating agency, or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.
The FortisBC Energy companies may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Company uses netting arrangements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist. The following table summarizes the FortisBC Energy companies' net credit risk exposure to its counterparties, as well as credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as it relates to its natural gas swaps and options.
| |
As at |
| |
March 31, |
December 31, |
| ($ millions, except for number of counterparties) |
2013 |
2012 |
| Gross credit exposure before credit collateral (1) |
33 |
51 |
| Credit collateral |
- |
- |
| Net credit exposure (2) |
33 |
51 |
| |
|
|
| Number of counterparties > 10% |
4 |
4 |
| Net exposure to counterparties > 10% |
30 |
45 |
| |
|
| (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, 2013, the Corporation had a long-term other asset of $106 million (December 31, 2012 - $104 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, 2013, Belize Electricity owed Belize Electric Company Limited ("BECOL") approximately US$6 million for energy purchases of which US$4 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. As at March 31, 2013, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $295 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at March 31, 2013, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.4 billion, of which $2.0 billion was unused including $910 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 $2.3 billion of the total credit facilities are committed credit facilities with maturities ranging from 2013 to 2017.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
| |
|
|
|
|
|
As at |
|
| |
Regulated |
|
Fortis |
Corporate |
|
March 31, |
|
December 31, |
|
| ($ millions) |
Utilities |
|
Properties |
and Other |
|
2013 |
|
2012 |
|
| Total credit facilities |
1,383 |
|
13 |
1,030 |
|
2,426 |
|
2,460 |
|
| Credit facilities utilized: |
|
|
|
|
|
|
|
|
|
| |
Short-term borrowings (1) |
(89 |
) |
- |
- |
|
(89 |
) |
(136 |
) |
| |
Long-term debt (2) |
(178 |
) |
- |
(88 |
) |
(266 |
) |
(150 |
) |
| Letters of credit outstanding |
(66 |
) |
- |
(2 |
) |
(68 |
) |
(67 |
) |
| Credit facilities unused |
1,050 |
|
13 |
940 |
|
2,003 |
|
2,107 |
|
| |
|
| (1) |
The weighted average interest rate on short-term borrowings was approximately 2.1% as at March 31, 2013 (December 31, 2012 - 1.9%). |
| |
|
| (2) |
As at March 31, 2013, no credit facility borrowings classified as long term were included in current installments of long-term debt on the consolidated balance sheet (December 31, 2012 - $20 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.2% as at March 31, 2013 (December 31, 2012 - 2.1%). |
As at March 31, 2013 and December 31, 2012, 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 January 2013 FEVI's $20 million unsecured committed non-revolving credit facility matured and was not replaced.
In April 2013 FortisBC Electric renegotiated and amended its credit facility agreement resulting in an extension to the maturity of the Company's $150 million unsecured committed revolving credit facility with $100 million now maturing in May 2016 and $50 million now maturing in May 2014. The amended credit facility agreement contains substantially similar terms and conditions as the previous credit facility agreement.
In April 2013 FHI extended its $30 million unsecured committed revolving credit facility to mature in May 2014 from May 2013. The new agreement contains substantially similar terms and conditions as the previous credit facility agreement.
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, 2013, the Corporation's credit ratings were as follows:
| Standard & Poor's ("S&P") |
A- (long-term corporate and unsecured debt credit rating) |
| DBRS |
A (low) (unsecured debt credit rating) |
In February 2013 S&P and DBRS affirmed the Corporation's debt credit ratings. 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, management's commitment to maintaining low levels of debt at the holding company level, the Corporation's reasonable credit metrics and its demonstrated ability and continued focus on acquiring and integrating stable regulated utility businesses financed on a conservative basis. The credit ratings also reflect the Corporation's financing plans for the pending acquisition of CH Energy Group and the expected completion of the Waneta Expansion hydroelectric generating facility on time and on budget.
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 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 Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and BECOL is the US dollar.
As at March 31, 2013, the Corporation's corporately issued US$557 million (December 31, 2012 - US$557 million) long-term debt had been designated as an effective hedge of the Corporation's foreign net investments. As at March 31, 2013, the Corporation had approximately US$16 million (December 31, 2012 - US$17 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 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 from 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 (Note 20). 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 $2 million during the three months ended March 31, 2013 ($1.5 million foreign exchange loss for the three months ended March 31, 2012) (Note 8).
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk associated with credit facility borrowings. 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 Caribbean Utilities is exposed to commodity price risk associated with changes in the market price for fuel (Notes 16 and 17). The risks have been reduced by entering into natural gas derivatives and fuel option contracts that effectively fix the price of natural gas purchases and fuel purchases, respectively. The natural gas derivatives and fuel option contracts 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, subject to regulatory approval, 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 in 2011, 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 maturity and the FortisBC Energy companies' ability to fully recover the commodity 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 2012 annual audited consolidated financial statements, except as described as follows.
Maritime Electric has entitlement to approximately 4.7% of the output from the New Brunswick Power Point Lepreau nuclear generating station ("Point Lepreau") for the life of the unit. As part of its entitlement, Maritime Electric is required to pay its share of the capital and operating costs of the unit. A major refurbishment of Point Lepreau that began in 2008 was completed and the station returned to service in November 2012. The refurbishment is expected to extend the facility's estimated life an additional 27 years and, as a result, the total estimated capital cost obligation has increased approximately $51 million from that disclosed in the 2012 annual audited consolidated financial statements.
A portion of the acquisition purchase price of CH Energy Group is expected to be funded from net proceeds from the $601 million Subscription Receipts offering, issued by the Corporation in June 2012, which proceeds are being held in escrow (Note 4). The Subscription Receipts Agreement ("Agreement") contains a deadline of June 30, 2013 for the release of the proceeds from the offering. If it is determined that PSC approval will not be received in time to allow closing of the acquisition of CH Energy Group to occur on or before June 30, 2013, Fortis may seek an extension of the June 30, 2013 deadline by way of amendment of the Agreement. The Agreement may be amended by a special resolution approved by at least two-thirds of the Subscription Receipts Holders ("Receipts Holders") at a meeting, either in person or by proxy, with a quorum for the meeting of at least two Receipts Holders collectively holding 25% of the Subscription Receipts. If conditions precedent to the closing of the transaction are not fulfilled or waived by June 30, 2013, or by the extension date for the Subscription Receipts if approved by Receipts Holders, or if the agreement and plan of merger related to the acquisition is terminated prior to such time, the proceeds from the Subscription Receipts offering, plus pro rata interest earned, are required to be returned to the Receipts Holders. As a result, closing of the transaction subsequent to June 30, 2013, or the extension date for the Subscription Receipts if approved by Receipts Holders, could result in the Corporation having to raise alternative capital to finance the acquisition.
20. EXPROPRIATED ASSETS
Belize Electricity
On June 20, 2011, the GOB enacted legislation leading to the expropriation of the Corporation's investment in Belize Electricity. Consequent to the deprivation of control over the operations of the utility, the Corporation discontinued the consolidation method of accounting for Belize Electricity, as of June 20, 2011, and classified the book value, including foreign exchange impacts, of the expropriated investment as a long-term other asset on the consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with respect to challenging the constitutionality of the expropriation of the Corporation's investment in Belize Electricity. Fortis commissioned an independent valuation of its expropriated investment and submitted its claim for compensation to the GOB in November 2011. The book value of the long-term other asset is below fair value as at the date of expropriation as determined by independent valuators. The GOB also commissioned a valuation of Belize Electricity which is significantly lower than both the fair value determined under the Corporation's valuation and the book value of the long-term other asset.
In July 2012 the Belize Supreme Court dismissed the Corporation's claim of October 2011. Also in July 2012, Fortis filed its appeal of the above-noted trial judgment in the Belize Court of Appeal. The appeal was heard in October 2012 and a decision 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 reasonable 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 $106 million, including foreign exchange impacts, as at March 31, 2013 (December 31, 2012 and March 31, 2012 - $104 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) the ordering of the return of the shares to Fortis and/or award of damages; or (ii) the ordering of compensation to be paid to Fortis for the unconstitutional expropriation of the shares. Based on presently available information, the long-term other asset is not deemed impaired as at March 31, 2013. 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. CONTINGENT LIABILITIES
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 effect on the Corporation's consolidated financial position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
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 proposed 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 proposed 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.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of Assessment from Canada Revenue Agency for additional taxes related to the taxation years 1999 through 2003. The exposure has been fully provided for in the consolidated financial statements. FHI is appealing these assessments.
In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia 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 interim 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 now 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. In addition, private landowners have filed separate writs and statements of claim dated August 19, 2005 and August 22, 2005 in relation to the same matter, which claims have now been settled. 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 interim consolidated financial statements.
The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which includes 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 utility 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 interim 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 distribution utility in Canada, with total assets of approximately $15 billion and fiscal 2012 revenue totalling approximately $3.7 billion. The Corporation serves more than two million gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets in Canada, Belize and Upstate New York. It also owns hotels and commercial office and retail space in Canada.
The Common Shares; First Preference Shares, Series C; 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; and Subscription Receipts of Fortis are listed on the Toronto Stock Exchange and trade under the ticker symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.J and FTS.R, respectively.
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Additional information, including the Fortis 2012 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.