ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net earnings attributable to common equity shareholders of $100 million, or $0.58 per common share, compared to $92 million, or $0.54 per common share, for the first quarter of 2009.
Performance for the quarter was driven by the Terasen Gas companies and Canadian Regulated Electric Utilities. However, growth in earnings was tempered by lower contributions from non-regulated hydroelectric generation operations and Caribbean Regulated Electric Utilities, and higher preference share dividends.
During the fourth quarter of 2009, regulatory decisions were received increasing the allowed rate of return on common shareholder's equity ("ROE") and/or the common equity component of total capital structure ("equity component") at the Corporation's four largest utilities. Effective January 1, 2009, the allowed ROE at FortisAlberta increased to 9.00 per cent from an interim allowed ROE for 2009 of 8.51 per cent and the utility's equity component increased to 41 per cent from 37 per cent. Effective July 1, 2009, the allowed ROE at Terasen Gas Inc. ("TGI") increased to 9.50 per cent from 8.47 per cent. Effective January 1, 2010, the equity component for TGI increased to 40 per cent from 35 per cent. TGI also received regulatory approval of a Negotiated Settlement Agreement ("NSA") for its 2010-2011 revenue requirements. A previous agreement had provided for the sharing of earnings above or below the allowed ROE with customers. The recently approved NSA does not include an earnings' sharing mechanism. At FortisBC, the allowed ROE increased to 9.90 per cent from 8.87 per cent, effective January 1, 2010. FortisBC also received regulatory approval of an NSA for its 2010 revenue requirements. Newfoundland Power received regulatory approval for its 2010 revenue requirements and the Company's allowed ROE has been set at 9.00 per cent for 2010, up from 8.95 per cent for 2009.
The Terasen Gas companies contributed earnings of $73 million, up $15 million from the first quarter of 2009, mainly due to an increase in the allowed ROE and an increase to the equity component at TGI. Due to the seasonality of the business, most of the earnings of the Terasen Gas companies are generated in the first and fourth quarters.
Canadian Regulated Electric Utilities contributed earnings of $40 million, up $3 million from the first quarter of 2009, related to FortisAlberta and Newfoundland Power. Earnings increased at FortisAlberta due to a higher allowed ROE and equity component compared to those reflected in earnings for the first quarter of 2009, combined with growth in electrical infrastructure investment and customers. Earnings at Newfoundland Power improved mainly as a result of growth in electrical infrastructure investment, higher electricity sales and timing differences favourably impacting operating expenses during the quarter.
On June 30, 2010, Randy Jesperson will retire as President and CEO of Terasen Inc. and John Walker, President and CEO of FortisBC Inc., will also become President and CEO of Terasen Inc. "We extend our gratitude to Randy for his leadership, commitment and valuable contribution since Fortis acquired Terasen in 2007. With John as President and CEO of both of our regulated utilities in British Columbia, we are assured a consistent focus and strategy in the delivery of energy to our customers," says Stan Marshall, President and Chief Executive Officer, Fortis Inc.
Caribbean Regulated Electric Utilities contributed $4 million to earnings compared to $6 million for the first quarter of 2009. Excluding a one-time gain of approximately $1 million at Fortis Turks and Caicos in the first quarter of 2009 and the approximate $1 million unfavourable impact of foreign exchange rates associated with the weakening of the US dollar, earnings were comparable quarter over quarter. Electricity sales were 3.6 per cent higher than in the same quarter last year, reflecting the favourable impact on energy demand of warmer and drier weather conditions experienced on Grand Cayman, combined with overall customer growth.
Non-Regulated Fortis Generation contributed $2 million to earnings compared to $6 million for the first quarter of 2009. The decrease was due to the expiry of the water rights of the Rankine hydroelectric generating facility in Ontario in April 2009 at the end of a 100-year term combined with decreased hydroelectric production in Belize associated with lower rainfall. Earnings from the Rankine facility were approximately $3 million during the first quarter of 2009.
The US$53 million 19-megawatt hydroelectric generating facility at Vaca in Belize was commissioned in March 2010, delivering 4 gigawatt hours of energy during the quarter.
Fortis Properties delivered earnings of $2 million, consistent with earnings for the first quarter of 2009.
Corporate and other expenses were $21 million compared to $17 million for the same quarter in 2009. The increase in expenses was mainly attributable to dividends associated with the First Preference Shares, Series H that were issued in January 2010 and interest expense on the $200 million 6.51% unsecured debentures issued in July 2009.
Net proceeds from the $250 million five-year fixed rate reset preference shares issued in January were used to repay borrowings under the Corporation's committed credit facility and to fund an equity injection into TGI to repay borrowings under the Company's credit facilities.
Subsequent to the quarter end, Terasen Inc. redeemed in full for cash its $125 million 8.0% Capital Securities.
Common shareholders of Fortis received a dividend of 28 cents per common share on March 1, 2010, up from 26 cents in the fourth quarter of 2009. The 7.7 per cent increase in the quarterly common share dividend translates into an annualized dividend of $1.12 and extends the Corporation's record of annual common share dividend increases to 37 consecutive years, the longest record of any public corporation in Canada.
Consolidated capital expenditures, before customer contributions, were approximately $188 million in the first quarter of 2010. Much of the Corporation's consolidated capital expenditure program is being driven by Regulated Utilities in western Canada.
Cash flow from operating activities was $249 million for the quarter, up $20 million from the same quarter last year, driven by higher earnings and favourable working capital changes.
As at March 31, 2010, Fortis had consolidated credit facilities of approximately $2.2 billion, of which $1.6 billion was unused, including $547 million unused under the Corporation's $600 million committed revolving credit facility. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which currently have maturities between 2011 and 2013.
"Our 2010 capital program of more than $1 billion is continuing as planned," says Marshall. "Over the next five years, capital expenditures are expected to approach $5 billion, driven by ongoing investment in infrastructure at our Regulated Utilities in western Canada."
"We will continue to build our business profitably through investment in existing operations and the pursuit of strategic acquisitions of regulated electric and gas utilities in the United States, Canada and the Caribbean," concludes Marshall.
FORWARD-LOOKING STATEMENT
The following analysis should be read in conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2010 and the Management Discussion and Analysis ("MD&A") and audited consolidated financial statements for the year ended December 31, 2009 included in the Corporation's 2009 Annual Report. This material has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations relating to MD&As. Financial information in this release has been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the "safe harbour" provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to the Corporation's management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected timing of regulatory decisions; expected consolidated forecasted gross capital expenditures for 2010 and in total over the five-year period from 2010 through 2014; the expectation that the Corporation's significant capital program should drive growth in earnings and dividends; the expected increase in average annual energy production from the Macal River in Belize by the Vaca hydroelectric generating facility; expected consolidated long-term debt maturities and repayments on average annually over the next five years; the expectation of no material adverse credit rating actions in the near term; expected sources of financing for the subsidiaries' capital expenditure programs; and except for debt at Belize Electricity and Exploits River Hydro Partnership ("Exploits Partnership"), the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2010. 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 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 event; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no significant decline in capital spending in 2010; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the continued ability to hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas commodity prices; no significant variability in interest rates; 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 supply; the continued ability to fund defined benefit pension plans; the absence of significant changes in government energy plans and environmental laws that may materially affect the operations and cash flows of the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no material decrease in market energy sales prices; maintenance of information technology infrastructure; 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. Factors which could cause results or events to differ from current expectations include, but are not limited to: regulatory risk; operating and maintenance risks; economic conditions; capital resources and liquidity risk; weather and seasonality; commodity price risk; derivative financial instruments and hedging; interest rate risk; counterparty risk; competitiveness of natural gas; natural gas supply; defined benefit pension plan performance and funding requirements; risks related to the development of the Terasen Gas (Vancouver Island) Inc. franchise; the Government of British Columbia's Energy Plan; environmental risks; insurance coverage risk; loss of licences and permits; loss of service area; market energy sales prices; changes in the current assumptions and expectations associated with the transition to International Financial Reporting Standards; changes in tax legislation; information technology infrastructure; an ultimate resolution of the expropriation of the assets of the Exploits Partnership that differs from what is currently expected by management; an unexpected outcome of legal proceedings currently against the Corporation; relation with First Nations; labour relations; and human resources. For additional information with respect to the Corporation's risk factors, reference should be made to the Corporation's continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and to the heading "Business Risk Management" in the MD&A for the three months ended March 31, 2010 and for the year ended December 31, 2009.
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.
COMPANY OVERVIEW AND FINANCIAL HIGHLIGHTS
Fortis is the largest investor-owned distribution utility in Canada, serving approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State, and hotels and commercial office and retail space primarily in Atlantic Canada. Year-to-date March 31, 2010, the Corporation's electricity distribution systems met a combined peak demand of approximately 5,015 megawatts ("MW") and its gas distribution system met a peak day demand of 1,006 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2010.
The key goals of the Corporation's regulated utilities are to operate sound gas and electricity distribution systems, deliver gas and electricity safely and reliably to customers at the lowest reasonable cost and conduct business in an environmentally responsible manner. The Corporation's main business, utility operations, is highly regulated. It is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets.
Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. Key financial highlights, including earnings by reportable segment, for the first quarter ended March 31, 2010 and March 31, 2009 are provided in the following tables.
/T/
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Financial Highlights (Unaudited) Quarter Ended March 31
2010 2009 Variance
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Revenue ($ millions) 1,076 1,202 (126)
Cash Flow from Operating Activities ($
millions) 249 229 20
Net Earnings Attributable to Common Equity
Shareholders ($ millions) 100 92 8
Basic Earnings per Common Share ($) 0.58 0.54 0.04
Diluted Earnings per Common Share ($) 0.56 0.52 0.04
Weighted Average Number of Common Shares
Outstanding (millions) 171.6 169.4 2.2
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Segmented Net Earnings Attributable to
Common Equity Shareholders (Unaudited) Quarter Ended March 31
($ millions) 2010 2009 Variance
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Regulated Gas Utilities - Canadian
Terasen Gas Companies (1) 73 58 15
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Regulated Electric Utilities - Canadian
FortisAlberta 14 12 2
FortisBC (2) 14 14 -
Newfoundland Power 7 6 1
Other Canadian (3) 5 5 -
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40 37 3
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Regulated Electric - Caribbean (4) 4 6 (2)
Non-Regulated - Fortis Generation (5) 2 6 (4)
Non-Regulated - Fortis Properties (6) 2 2 -
Corporate and Other (7) (21) (17) (4)
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Net Earnings Attributable to Common Equity
Shareholders 100 92 8
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(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island)
Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI")
(2) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant
and Arrow Lakes hydroelectric generating plants and the distribution
system owned by the City of Kelowna. Excludes the non-regulated
generation operations of FortisBC Inc.'s wholly owned partnership,
Walden Power Partnership.
(3) Includes Maritime Electric and FortisOntario. FortisOntario includes
Canadian Niagara Power, Cornwall Electric and, from October 2009,
Algoma Power Inc. ("Algoma Power")
(4) Includes Belize Electricity, in which Fortis holds an approximate 70
per cent controlling interest; Caribbean Utilities on Grand Cayman,
Cayman Islands, in which Fortis holds an approximate 59 per cent
controlling interest; and wholly owned Fortis Turks and Caicos
(5) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State, with a combined generating capacity of 139 megawatts ("MW"),
mainly hydroelectric. Prior to May 1, 2009, the financial results of
Fortis reflected earnings' contribution associated with the
Corporation's 75-MW water-right entitlement on the Niagara River in
Ontario related to the Rankine hydroelectric generating facility. The
water rights expired on April 30, 2009, at the end of a 100-year term.
Additionally, prior to February 12, 2009, the financial results of the
hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. Effective February
12, 2009, the Corporation discontinued the consolidation method of
accounting for the generation operations in central Newfoundland due
to the Corporation no longer having control over the operations and
cash flows, as a result of the expropriation of the assets of the
Exploits River Hydro Partnership by the Government of Newfoundland and
Labrador. For a further discussion of this matter, refer to the
"Critical Accounting Estimates - Contingencies" section of the MD&A
for the year ended December 31, 2009.
(6) Fortis Properties owns and operates 21 hotels, comprised of more than
4,100 rooms, in eight Canadian provinces and approximately 2.8 million
square feet of commercial office and retail space primarily in
Atlantic Canada.
(7) Includes Fortis net corporate expenses, net expenses of
non-regulated Terasen Inc. ("Terasen") corporate-related activities
and the financial results of Terasen's 30 per cent ownership interest
in CustomerWorks Limited Partnership ("CWLP") and of Terasen's non-
regulated wholly owned subsidiary Terasen Energy Services Inc. ("TES")
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/T/
SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
TERASEN GAS COMPANIES
/T/
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Gas Volumes by Major Customer Category
(Unaudited) Quarter Ended March 31
(TJ) 2010 2009 Variance
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Core - Residential and Commercial 40,431 50,412 (9,981)
Industrial 1,675 2,310 (635)
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Total Sales Volumes 42,106 52,722 (10,616)
Transportation Volumes 16,410 20,249 (3,839)
Throughput under Fixed Revenue Contracts 4,668 4,999 (331)
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Total Gas Volumes 63,184 77,970 (14,786)
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/T/
Significant Factors Affecting Gas Volumes Variance
Unfavourable
/T/
-- Lower average consumption by residential and commercial customers as a
result of warmer weather quarter over quarter
-- Transportation volumes were negatively impacted by unfavourable
economic conditions affecting the forestry sector combined with the
ability of certain transportation customers to switch to alternative
fuels
/T/
Net customer additions were 1,566 during the first quarter of 2010 compared to 2,256 during the same quarter of 2009. While gross customer additions increased quarter over quarter, customer disconnections were also higher due to warmer weather. Growth in multi-family housing, where natural gas use is less prevalent compared to single-family housing, has also resulted in lower customer growth quarter over quarter.
Seasonality has a material impact on the earnings of the Terasen Gas companies as a major portion of the gas distributed is used for space heating. Most of the annual earnings of the Terasen Gas companies are generated in the first and fourth quarters.
The Terasen Gas companies earn approximately the same margin regardless of whether a customer contracts for the purchase of natural gas or for the transportation only of natural gas.
As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and energy supply costs from those forecasted to set gas rates do not materially affect earnings.
/T/
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Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2010 2009 Variance
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Revenue 529 669 (140)
Energy Supply Costs 305 468 (163)
Operating Expense 70 67 3
Amortization 30 25 5
Finance Charges 27 32 (5)
Corporate Taxes 24 19 5
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Earnings 73 58 15
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/T/
Significant Factors Affecting Revenue Variance
Unfavourable
/T/
-- Lower commodity cost of natural gas charged to customers
-- Lower average gas consumption per customer
/T/
Favourable
/T/
-- Increased customer delivery rates, effective January 1, 2010, which
included the impact of the increase in the allowed rate of return on
common shareholder's equity ("ROE") to 9.50 per cent from 8.47 per cent
for Terasen Gas Inc. ("TGI") and to 10.00 per cent from 9.17 per cent
for Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas
Whistler Inc. ("TGWI"), and the increase in the deemed common equity
component of the total capital structure ("equity component") for TGI
to 40 per cent from 35 per cent
/T/
Significant Factors Affecting Earnings Variance
Favourable
/T/
-- The increase in customer delivery rates, effective January 1, 2010
-- Lower finance charges due to lower interest rates and lower average
credit facility borrowings quarter over quarter
/T/
Unfavourable
/T/
-- Higher operating expenses driven by: (i) increased labour and
employee-benefit costs; and (ii) the expensing of asset removal costs
to operating expenses, effective January 1, 2010, as a result of
regulator-approved Negotiated Settlement Agreements ("NSAs") related to
2010 and 2011 revenue requirements. These asset removal costs are being
collected in current customer delivery rates. Prior to 2010, asset
removal costs were recorded against accumulated amortization.
-- Increased amortization cost due to higher amortization rates quarter
over quarter, as determined and approved by the regulator upon review
of a current depreciation study. The increase in amortization is being
collected in current customer delivery rates.
/T/
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Terasen Gas companies, refer to the "Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
/T/
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Financial Highlights (Unaudited) Quarter Ended March 31
2010 2009 Variance
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Energy Deliveries (gigawatt hours ("GWh")) 4,109 4,152 (43)
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($ millions)
Revenue 87 79 8
Operating Expense 35 34 1
Amortization 24 22 2
Finance Charges 14 11 3
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Earnings 14 12 2
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/T/
Significant Factors Affecting Energy Deliveries Variance
Unfavourable
/T/
-- Decreased energy deliveries to farm and irrigation, oil and gas, and
industrial customers, mainly due to lower average consumption resulting
from relatively milder temperatures quarter over quarter
/T/
Favourable
/T/
-- Customer growth with the total number of customers increasing by 2,100
during the first quarter of 2010
/T/
FortisAlberta's distribution revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
Significant Factors Affecting Revenue Variance
Favourable
/T/
-- An interim average 7.5 per cent increase in base customer electricity
distribution rates, effective January 1, 2010, combined with a rate
revenue accrual during the first quarter of 2010 for future collection
from customers relating to certain approved deferral account items.
Final approval of FortisAlberta's 2010-2011 Revenue Requirements
Application is expected in the second quarter of 2010.
-- A rate revenue accrual of approximately $1 million during the first
quarter of 2010 to reflect an allowed ROE of 9.00 per cent, compared to
an interim allowed ROE of 8.51 per cent as reflected in revenue during
the first quarter of 2009, and an increase in the equity component to
41 per cent from 37 per cent as reflected in revenue during the first
quarter of 2009
-- Customer growth, as described above
/T/
Unfavourable
/T/
-- An approximate $2 million decrease in miscellaneous revenue
Significant Factors Affecting Earnings Variance
/T/
Favourable
/T/
-- The increase in customer electricity distribution rate revenue, for the
reasons discussed above
/T/
Unfavourable
/T/
-- Increased operating expenses, mainly due to higher labour costs and
general operating expenses
-- Increased amortization cost associated with continued investment in
utility capital assets, partially offset by the impact of the
commencement of capitalization of depreciation for vehicles and tools
used in the construction of other assets in 2010, as approved by the
regulator
-- Increased finance charges due to higher debt levels in support of the
Company's significant capital expenditure program, partially offset by
the impact of lower interest rates on lower average credit facility
borrowings
/T/
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisAlberta, refer to the "Regulatory Highlights" section of this MD&A.
FORTISBC
/T/
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Financial Highlights (Unaudited) Quarter Ended March 31
2010 2009 Variance
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Electricity Sales (GWh) 820 903 (83)
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($ millions)
Revenue 72 72 -
Energy Supply Costs 21 22 (1)
Operating Expense 17 17 -
Amortization 10 10 -
Finance Charges 8 7 1
Corporate Taxes 2 2 -
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Earnings 14 14 -
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/T/
Significant Factors Affecting Electricity Sales Variance
Unfavourable
/T/
-- Lower average consumption due to warmer temperatures experienced during
the first quarter of 2010 compared to cooler temperatures experienced
during the first quarter of 2009
/T/
Favourable
/T/
-- Residential and general service customer growth
/T/
Significant Factors Affecting Revenue Variance
Unfavourable
/T/
-- The 9.2 per cent decrease in electricity sales
/T/
Favourable
/T/
-- A 6.0 per cent increase in customer electricity rates, effective
January 1, 2010, reflecting an increase in the allowed ROE to 9.90
per cent for 2010, up from 8.87 per cent for 2009, and ongoing
investment in electrical infrastructure
-- Increased performance-based rate-setting ("PBR") incentive adjustments
receivable from customers
-- Higher revenue contribution from non-regulated operating, maintenance
and management services
/T/
Significant Factors Affecting Earnings Variance
Favourable
/T/
-- The 6.0 per cent increase in customer electricity rates, effective
January 1, 2010
-- Increased PBR incentive adjustments, as discussed above
-- Lower energy supply costs associated with decreased electricity sales
and a higher proportion of energy generated from Company-owned
hydroelectric generating facilities versus purchased power, partially
offset by the impact of higher average prices for purchased power
-- Lower than expected operating expenses in the first quarter of 2010 due
to the timing of operating and maintenance projects and their related
expenditures
/T/
Unfavourable
/T/
-- Higher finance charges due to higher debt levels in support of the
Company's capital expenditure program and higher fees and interest
rates on credit facility borrowings
-- The 9.2 per cent decrease in electricity sales
/T/
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisBC, refer to the "Regulatory Highlights" section of this MD&A.
NEWFOUNDLAND POWER
/T/
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Financial Highlights (Unaudited) Quarter Ended March 31
2010 2009 Variance
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Electricity Sales (GWh) 1,795 1,763 32
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($ millions)
Revenue 178 169 9
Energy Supply Costs 131 127 4
Operating Expense 16 14 2
Amortization 11 11 -
Finance Charges 9 8 1
Corporate Taxes 4 3 1
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Earnings 7 6 1
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/T/
Significant Factors Affecting Electricity Sales Variance
Favourable
/T/
-- Customer growth
/T/
Significant Factors Affecting Revenue Variance
Favourable
/T/
-- An average 3.5 per cent increase in customer electricity rates,
effective January 1, 2010, reflecting an increase in the allowed ROE to
9.00 per cent for 2010, up from 8.95 per cent for 2009, and higher rate
base and operating expenses, including pension costs
-- A 1.8 per cent increase in electricity sales
/T/
Significant Factors Affecting Earnings Variance
Favourable
/T/
-- The average 3.5 per cent increase in customer electricity rates,
effective January 1, 2010
-- The 1.8 per cent increase in electricity sales
-- Lower than expected operating labour costs due to the timing of capital
projects. Good weather conditions during the first quarter of 2010
allowed for an early start to capital projects and there was also an
increase in capital work associated with an ice storm in March 2010.
/T/
Unfavourable
/T/
-- Higher pension costs, wage and inflationary cost increases, increased
conservation costs and higher retirement and severance expenses
-- Higher finance charges associated with interest expense on the $65
million 6.606% bonds issued in May 2009, partially offset by lower
average credit facility borrowings and lower interest rates on those
borrowings
/T/
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Newfoundland Power, refer to the "Regulatory Highlights" section of this MD&A.
OTHER CANADIAN ELECTRIC UTILITIES
/T/
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Financial Highlights (Unaudited) (1) Quarter Ended March 31
2010 2009 Variance
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Electricity Sales (GWh) 632 616 16
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($ millions)
Revenue 82 71 11
Energy Supply Costs 53 47 6
Operating Expense 11 8 3
Amortization 5 4 1
Finance Charges 6 5 1
Corporate Taxes 2 2 -
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Earnings 5 5 -
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(1) Includes Maritime Electric and FortisOntario. FortisOntario includes
financial results of Algoma Power from October 8, 2009, the date of
acquisition.
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/T/
Significant Factors Affecting Electricity Sales Variance
Favourable
/T/
-- Electricity sales at Algoma Power Inc. ("Algoma Power") of 54 gigawatt
hours ("GWh") during the first quarter of 2010
/T/
Unfavourable
/T/
-- Lower average consumption due to more moderate temperatures experienced
on Prince Edward Island and in Ontario during the first quarter of
2010, combined with the impact of conservation initiatives and the
economic downturn. Excluding electricity sales at Algoma Power,
electricity sales decreased 6.2 per cent.
/T/
Significant Factors Affecting Revenue Variance
Favourable
/T/
-- Revenue contribution of $9 million from Algoma Power during the first
quarter of 2010
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- An average 5.3 per cent increase in customer electricity rates at
Maritime Electric, effective April 1, 2009, which reflects an increase
in the base amount of energy-related costs being expensed and collected
from customers and recorded in revenue through the basic rate component
of customer billings
-- A 5.1 per cent, an 11.7 per cent and an 8.4 per cent increase in
customer electricity distribution rates at Fort Erie, Gananoque and
Port Colborne in Ontario, respectively, effective May 1, 2009
/T/
Unfavourable
/T/
-- The 6.2 per cent decrease in electricity sales, excluding electricity
sales at Algoma Power
/T/
Significant Factors Affecting Earnings Variance
Favourable
/T/
-- Algoma Power contributed $0.4 million to earnings during the first
quarter of 2010
/T/
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Maritime Electric and FortisOntario, refer to the "Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CARIBBEAN
/T/
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Financial Highlights (Unaudited) (1) Quarter Ended March 31
2010 2009 Variance
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Average US:CDN Exchange Rate (2) 1.04 1.25 (0.21)
Electricity Sales (GWh) 256 247 9
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($ millions)
Revenue 76 83 (7)
Energy Supply Costs 45 46 (1)
Operating Expense 12 14 (2)
Amortization 9 11 (2)
Finance Charges 5 4 1
-------------------------------
5 8 (3)
Non-Controlling Interest 1 2 (1)
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Earnings 4 6 (2)
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(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00=US$1.00. The reporting
currency of Caribbean Utilities and Fortis Turks and Caicos is the US
dollar.
---------------------------------------------------------------------------
/T/
Significant Factors Affecting Electricity Sales Variance
Favourable
/T/
-- Warmer and drier weather conditions experienced on Grand Cayman, which
increased air conditioning load
-- Overall customer growth for the segment, including a new system-
connected medical facility and condominium complex in the Turks and
Caicos Islands
-- A relatively strong winter tourist season experienced in the Turks and
Caicos Islands in 2010
/T/
Significant Factors Affecting Revenue Variance
Unfavourable
/T/
-- Approximately $15 million unfavourable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar quarter over
quarter
-- Revenue during the first quarter of 2009 included approximately $1
million associated with a favourable appeal judgment at Fortis Turks
and Caicos related to a customer rate classification matter.
/T/
Favourable
/T/
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities due to an increase in the cost of fuel
-- A 3.6 per cent increase in electricity sales
-- A 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
/T/
Significant Factors Affecting Earnings Variance
Unfavourable
/T/
-- Approximately $1 million associated with unfavourable foreign currency
translation
-- The favourable impact on energy supply costs during the first quarter
of 2009, due to a change in the methodology for calculating the cost of
fuel recoverable from customers at Fortis Turks and Caicos
-- Higher finance charges, excluding the impact of foreign exchange,
mainly associated with interest expense on the US$40 million 7.5%
unsecured notes issued in May and July 2009 at Caribbean Utilities and
interest expense on regulatory liabilities at Belize Electricity
-- Revenue during the first quarter of 2009 included approximately $1
million associated with the favourable appeal judgment at Fortis Turks
and Caicos.
/T/
Favourable
/T/
-- The 3.6 per cent increase in electricity sales
-- The 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
/T/
For additional information on the nature of regulation and material regulatory decisions and applications pertaining to Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of this MD&A.
NON-REGULATED - FORTIS GENERATION
/T/
---------------------------------------------------------------------------
Financial Highlights (Unaudited) (1) Quarter Ended March 31
2010 2009 (2) Variance
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Energy Sales (GWh) 64 257 (193)
---------------------------------------------------------------------------
($ millions)
Revenue 5 16 (11)
Energy Supply Costs - 1 (1)
Operating Expense 2 4 (2)
Amortization 1 2 (1)
Finance Charges - 1 (1)
Corporate Taxes - 2 (2)
---------------------------------------------------------------------------
Earnings 2 6 (4)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State
(2) Results reflect contribution from the Rankine hydroelectric generating
facility in Ontario until April 30, 2009. On April 30, 2009, the
Rankine water rights expired at the end of a 100-year term.
---------------------------------------------------------------------------
/T/
Significant Factors Affecting Energy Sales Variance
Unfavourable
/T/
-- The expiration on April 30, 2009 of the water rights of the Rankine
hydroelectric generating facility in Ontario. Energy sales for the
first quarter of 2009 included approximately 168 GWh related to
Rankine.
-- Lower production in Belize due to lower rainfall
-- Energy sales for the first quarter of 2009 included energy sales of 19
GWh related to central Newfoundland operations up until February 12,
2009, at which point the consolidation method of accounting for these
operations was discontinued necessitated by the actions of the
Government of Newfoundland and Labrador related to expropriation of
the assets of the Exploits River Hydro Partnership (the "Exploits
Partnership")
/T/
Favourable
/T/
-- The new Vaca hydroelectric generating facility was commissioned in
March 2010. The facility is expected to increase average annual energy
production from the Macal River in Belize by approximately 80 GWh.
Production by the facility was only 4 GWh for the first quarter due to
low rainfall and the commissioning of the facility late in the quarter.
/T/
Significant Factors Affecting Revenue Variance
Unfavourable
/T/
-- The loss of revenue subsequent to the expiration of the Rankine water
rights in April 2009
-- The discontinuance of the consolidation method of accounting for the
financial results of the Exploits Partnership during the first quarter
of 2009
-- Lower production in Belize
-- Approximately $1 million unfavourable foreign exchange associated with
the translation of US dollar-denominated revenue, due to the weakening
of the US dollar relative to the Canadian dollar quarter over quarter
/T/
Significant Factors Affecting Earnings Variance
Unfavourable
/T/
-- The expiration of the Rankine water rights. Earnings' contribution
associated with the Rankine hydroelectric generating facility was
approximately $3 million during the first quarter of 2009.
-- Lower production in Belize
/T/
Favourable
/T/
-- Reduced finance charges as a result of higher interest revenue
associated with inter-company lending to regulated operations in
Ontario
/T/
NON-REGULATED - FORTIS PROPERTIES
/T/
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Hospitality Revenue 32 31 1
Real Estate Revenue 17 16 1
--------------------------------------------------------------------------
Total Revenue 49 47 2
Operating Expense 36 34 2
Amortization 4 4 -
Finance Charges 6 6 -
Corporate Taxes 1 1 -
--------------------------------------------------------------------------
Earnings 2 2 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
/T/
Significant Factors Affecting Revenue Variance
Favourable
/T/
-- Revenue contribution from the Holiday Inn Select Windsor, acquired in
April 2009, combined with overall higher revenue contribution from
hotel properties in Atlantic Canada, partially offset by overall lower
revenue contribution from hotel properties in western Canada
-- Revenue growth at all regions of the Real Estate Division, mainly due
to rent increases and higher operating expense recoveries
-- A $0.2 million gain on sale of land in central Newfoundland
/T/
Unfavourable
/T/
-- A 2.3 per cent decrease in revenue per available room ("RevPAR") at the
Hospitality Division to $62.93 for the first quarter of 2010 from
$64.40 for the same quarter in 2009. RevPAR decreased due to an overall
4.1 per cent decrease in hotel occupancy, mainly at operations in
western Canada, partially offset by an overall 1.9 per cent increase in
average room rates. Average room rates at operations in Atlantic and
western Canada increased, while rates at operations in central Canada
decreased, quarter over quarter.
-- A decrease in the occupancy rate at the Real Estate Division to 95.8
per cent as at March 31, 2010 from 96.0 per cent as at March 31, 2009
/T/
Significant Factors Affecting Earnings Variance
/T/
-- Improved performance at the Real Estate Division, contribution from the
Holiday Inn Select Windsor and improved performance from hotel
operations in Atlantic Canada were mostly offset by the unfavourable
impact of lower occupancies at hotel operations in western Canada,
driven by the continued impact of the economic downturn.
/T/
CORPORATE AND OTHER
/T/
--------------------------------------------------------------------------
Financial Highlights (Unaudited) (1) Quarter Ended March 31
($ millions) 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 7 7 -
Operating Expense 4 3 1
Amortization 3 2 1
Finance Charges (2) 20 19 1
Corporate Tax Recovery (5) (4) (1)
------------------------------
(15) (13) (2)
Preference Share Dividends 6 4 2
--------------------------------------------------------------------------
Net Corporate and Other Expenses (21) (17) (4)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen corporate-related activities and the financial results of
Terasen's 30 per cent ownership interest in CWLP and of Terasen's non-
regulated wholly owned subsidiary TES
(2) Includes dividends on preference shares classified as long-term
liabilities
--------------------------------------------------------------------------
/T/
Significant Factors Affecting Net Corporate and Other Expenses Variance
Unfavourable
/T/
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series H in January 2010
-- Higher finance charges driven by interest expense on the 30-year $200
million 6.51% unsecured debentures issued in July 2009 and marginally
higher average credit facility borrowings, partially offset by lower
interest rates charged on those credit facility borrowings
/T/
Favourable
/T/
-- A favourable foreign exchange impact of approximately $1 million
associated with the translation of US dollar-denominated interest
expense, due to the weakening of the US dollar relative to the Canadian
dollar quarter over quarter
/T/
In January 2010, Fortis completed a $250 million five-year fixed rate reset preference share offering. The net proceeds of approximately $242 million were used to repay borrowings under the Corporation's committed credit facility and to fund an equity injection into TGI to repay borrowings under the utility's credit facilities in support of working capital and capital expenditure requirements.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications associated with each of the Corporation's regulated gas and electric utilities are summarized as follows:
Nature of Regulation
/T/
Allowed Returns Supportive
(%) Features
--------------------------- ---------------
Future or
Allowed Historical Test
Common Year Used
Regulated Regulatory Equity to Set Customer
Utility Authority (%) 2008 2009 2010 Rates
---------------------------------------------------------- ---------------
Cost of Service
("COS")/ROE
ROE
---------------------------
British TGI: Prior to
TGI Columbia January 1,
Utilities 2010, 50/50
sharing of
Commission 40 (1) 8.62 8.47(2)/ 9.50 earnings above
("BCUC") 9.50(3) or below the
allowed ROE
under a PBR
mechanism
that expired on
December 31,
2009
ROEs
TGVI BCUC 40 9.32 9.17(2) 10.00 established by
/10.00(3) the BCUC,
effective
July 1, 2009,
as a result of
a cost of
capital
decision in the
fourth quarter
of
2009.
Previously, the
allowed ROEs
were
set using an
automatic
adjustment
formula tied to
long-term
Canada bond
yields.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
FortisBC BCUC 40 9.02 8.87 9.90 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,
effective
January 1,
2010, as a
result of a
cost of
capital
decision in
2009.
Previously, the
allowed ROE was
set using an
automatic
adjustment
formula tied to
long-term
Canada bond
yields.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
Fortis Alberta
Alberta Utilities 41(4) 8.75 9.00 9.00 COS/ROE
Commission
("AUC")
ROE established
by the AUC,
effective
January 1,
2009, as a
result of a
generic
cost of capital
decision in the
fourth
quarter of
2009.
Previously, the
allowed
ROE was set
using an
automatic
adjustment
formula tied to
long-term
Canada bond
yields.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
Newfound- Newfoundland 45 8.95 8.95 9.00 COS/ROE
land and +/- +/- +/-
Power Labrador Board 50 bps 50 bps 50 bps ROE for 2010
of established by
Commissioners the PUB.
of Except for
Public 2010, the
Utilities allowed ROE is
("PUB") set using an
automatic
adjustment
formula
tied to long-
term Canada
bond yields.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
Maritime Island 40 10.00 9.75 9.75(5) COS/ROE
Electric Regulatory and
Appeals Future Test
Commission Year
("IRAC")
---------------------------------------------------------- ---------------
Fortis Ontario Canadian
Ontario Energy Niagara Power -
Board COS/ROE
("OEB")
Canadian 40(6) 9.00 8.01 8.01 Algoma Power -
Niagara COS/ROE and
Power subject to
Rural Rate
Protection
Subsidy
program
Algoma Power 50 N/A 8.57 9.75(5) Cornwall
Electric -
Price cap with
Franchise commodity cost
Agreement flow through
---------------
Cornwall Canadian
Electric Niagara Power -
2004 historical
test year for
2008; 2009 test
year beginning
in 2009
Algoma Power -
2007 historical
test year for
2009; 2010 test
year for 2010
---------------------------------------------------------- ---------------
Belize Public N/A 10.00 10.00 -(8) Four-year COS/
Elect- Utilities ROA agreements
ricity Commission
("PUC") Additional
costs in the
event of a
hurricane would
be deferred and
the
Company may
apply for
future recovery
in customer
rates.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
Caribbean Electricity N/A 9.00- 9.00- 7.75- COS/ROA
Utilit- Regulatory 11.00 11.00 9.75
ies Authority Rate-cap
("ERA") adjustment
mechanism based
on published
consumer price
indices
Under the new
transmission
and
distribution
licence, the
Company may
apply for a
special
additional rate
to
customers in
the event of a
disaster,
including a
hurricane.
---------------
Historical Test
Year
---------------------------------------------------------- ---------------
Fortis Utilities make N/A 17.50 17.50 17.50 COS/ROA
Turks annual filings (9) (9) (9)
and with the If the actual
Caicos Government ROA is lower
than the
allowed ROA,
due to
additional
costs
resulting from
a hurricane or
other event,
the Company may
apply for an
increase in
customer rates
in the
following year.
---------------
Future Test
Year
---------------------------------------------------------- ---------------
(1) Effective January 1, 2010. For 2008 and 2009, the allowed deemed
equity component of the capital structure was 35 per cent.
(2) Pre-July 1, 2009
(3) Effective July 1, 2009
(4) Effective January 1, 2009. For 2008, the allowed deemed equity
component of the capital structure was 37 per cent.
(5) Subject to regulatory approval
(6) Effective May 1, 2010. For 2009, effective May 1, the allowed deemed
equity component of the capital structure was 43.3 per cent.
(7) Rate of return on rate base assets
(8) Allowed ROA to be settled once regulatory matters are resolved
(9) Amount provided under licence. Actual ROAs achieved in 2008 and 2009
were materially lower than the ROA allowed under the licence due to
significant investment occurring at the utility.
---------------------------------------------------------------------------
/T/
Material Regulatory Decisions and Applications
/T/
--------------------------------------------------------------------------
Regulated Summary Description
Utility
--------------------------------------------------------------------------
TGI/TGVI - TGI and TGVI review with the BCUC natural gas and
propane commodity rates every three months and mid-
stream rates annually in order to ensure the flow
through rates charged to customers are sufficient to
cover the cost of purchasing natural gas and propane
and contracting for mid-stream resources, such as
third-party pipeline or storage capacity. The commodity
cost of natural gas and mid-stream costs are flowed
through to customers without markup. Effective January
1, 2010, the BCUC approved an increase in mid-stream
rates for natural gas and kept commodity rates for
natural gas unchanged for customers in the Lower
Mainland, Fraser Valley, Interior, North and the
Kootenay service areas. The BCUC also approved a
decrease in commodity rates for natural gas for
customers in Whistler, effective January 1, 2010.
Effective April 1, 2010, the BCUC approved an increase
in commodity rates for natural gas for customers in the
Lower Mainland, Fraser Valley, Interior, North and the
Kootenay service areas. There was no change in
commodity rates for natural gas for customers on
Vancouver Island and in Whistler.
- In November and December 2009, the BCUC approved: (i)
NSAs pertaining to the 2010 and 2011 Revenue
Requirements Applications for TGI and TGVI; (ii) an
increase in TGI's equity component, effective January
1, 2010, to 40 per cent from 35 per cent; (iii) an
increase in TGI's allowed ROE, effective July 1, 2009,
to 9.50 per cent from 8.47 per cent; and (iv) an
increase in the allowed ROE to 10.00 per cent,
effective July 1, 2009, from 9.17 per cent for each of
TGVI and TGWI. In its decision on the Return on Equity
and Capital Structure Application, the BCUC maintained
TGI as a benchmark utility for calculating the allowed
ROE for certain utilities regulated by the BCUC. The
BCUC also determined that the former automatic
adjustment formula used to establish the ROE annually
will no longer apply and the allowed ROEs as determined
in the BCUC decision will apply until reviewed further
by the BCUC. The BCUC-approved NSA for TGI did not
include a provision to allow the continued use of a PBR
mechanism after the expiry, on December 31, 2009, of
TGI's previous PBR agreement. The approved mid-year
rate base at TGI is $2,540 million for 2010 and $2,634
million for 2011, and the approved mid-year rate base
at TGVI is approximately $555 million for 2010 and $729
million for 2011. The impact of the approved NSAs,
increase in the allowed ROEs, and higher equity
component at TGI resulted in an increase in customer
rates, effective January 1, 2010. Customer rates for
TGVI's sales customers, however, will remain unchanged
for the two-year period beginning January 1, 2010, as
provided in the BCUC-approved NSA for TGVI.
- In February 2010, the BCUC approved TGI's application
for the in-sourcing of core elements of its customer
care services and implementation of a new customer
information system, upon the Company accepting a cost
risk-sharing condition, whereby TGI would share equally
with customers any costs or savings outside a band of
plus or minus 10 per cent of the approved total project
cost of approximately $116 million, including deferral
of certain operating and maintenance expenses.
--------------------------------------------------------------------------
FortisBC - In December 2009, the BCUC approved an NSA pertaining
to FortisBC's 2010 Revenue Requirements Application.
The result was a general customer electricity rate
increase of 6.0 per cent, effective January 1, 2010.
The rate increase was primarily the result of the
Company's ongoing investment in infrastructure,
increasing power supply costs and the higher cost of
capital. FortisBC's allowed ROE has increased to 9.90
per cent, effective January 1, 2010, from 8.87 per cent
in 2009 as a result of the BCUC decision to increase
the allowed ROE of TGI, the benchmark utility in
British Columbia. The BCUC-approved NSA assumes a mid-
year rate base of approximately $975 million for 2010.
--------------------------------------------------------------------------
FortisAlberta - In June 2009, FortisAlberta filed a comprehensive two-
year Distribution Revenue Requirements Application for
2010 and 2011. The application forecasts a mid-year
rate base of approximately $1,538 million for 2010 and
$1,724 million for 2011. The application proposes an
average increase in base customer distribution
electricity rates of 13.3 per cent for 2010 and 14.9
per cent for 2011, before considering the impact of the
increase in the allowed ROE and equity component, as
per the AUC 2009 Generic Cost of Capital Decision (the
"2009 GCOC Decision") as described below. The proposed
rate increases are primarily driven by the Company's
ongoing investment in infrastructure to support
customer growth and maintain and upgrade the
electricity system. In December 2009, FortisAlberta
provided the AUC with an update to the proposed
forecast revenue requirements for 2010 and 2011,
primarily to reflect the 2009 GCOC Decision. A decision
on the revenue requirements application is expected in
the second quarter of 2010. The AUC has approved an
interim average 7.5 per cent increase in base customer
electricity distribution rates at FortisAlberta,
effective January 1, 2010.
- The $4.1 million favourable 2009 cumulated annual
impact of the 2009 GCOC Decision was accrued as revenue
in the fourth quarter of 2009, which has been requested
to be collected in customer electricity rates in 2010.
- The 2009 GCOC Decision established a generic allowed
ROE of 9.00 per cent for each of 2009 and 2010 for all
Alberta utilities it regulates. This allowed ROE is up
from the interim allowed ROE of 8.51 per cent that was
applicable to FortisAlberta in 2009. The ROE automatic
adjustment formula will no longer apply until reviewed
further by the AUC. The AUC also increased
FortisAlberta's equity component to 41 per cent from 37
per cent, effective January 1, 2009.
- The AUC has initiated a process to reform utility rate
regulation in Alberta. The AUC has expressed its
intention to apply a PBR formula to distribution
service rates as early as July 1, 2012. FortisAlberta
is currently assessing PBR and will participate fully
in the AUC process.
--------------------------------------------------------------------------
Newfoundland - In December 2009, the PUB issued a decision on
Power Newfoundland Power's 2010 General Rate Application,
resulting in an overall average increase in customer
electricity rates of approximately 3.5 per cent,
effective January 1, 2010. The rate increase reflects
the impact of an increase in the allowed ROE to 9.00
per cent from 8.95 per cent in 2009, as set by the PUB
for 2010, and higher rate base and operating expenses,
including pension costs. The PUB decision assumes a
mid-year rate base of approximately $869 million for
2010. The PUB also ordered that Newfoundland Power's
allowed ROE for each of 2011 and 2012 be determined
using the ROE automatic adjustment formula.
- In March 2010, Newfoundland Power submitted an
application to the PUB with proposed changes to the
existing ROE automatic adjustment formula. In the
application, Newfoundland Power proposed the use of
Consensus Forecasts in determining the risk-free rate
for calculating the forecast cost of equity to be used
in the formula for 2011 and 2012. The previous approach
used a ten-day observation of long-term Canada Bond
yields as the forecast risk-free rate. In April 2010,
the PUB approved the Company's application as filed.
--------------------------------------------------------------------------
Maritime - In January 2010, Maritime Electric filed an application
Electric with IRAC: (i) providing a report on the impact of the
rebasing of the Energy Cost Adjustment Mechanism
deferral account in 2009 and requesting an increase in
the reference cost of energy in basic rates from 7.7
cents per kilowatt hour ("kWh") to 9.4 cents per kWh,
effective April 1, 2010, and from 9.4 cents per kWh to
9.6 cents per kWh, effective April 1, 2011; (ii)
requesting that the replacement energy costs incurred
during the refurbishment of the New Brunswick Power
Point Lepreau Nuclear Generating Station be amortized
over a period of 25 years, representing the extended
life of the unit; and (iii) requesting an allowed ROE
of 9.75 per cent for both 2010 and 2011, unchanged from
2009. A hearing on the application is expected during
the second quarter of 2010.
--------------------------------------------------------------------------
FortisOntario - In October and November 2009, FortisOntario filed
Third-Generation Incentive Rate Mechanism ("IRM")
electricity distribution rate applications for
harmonized rates for Fort Erie and Gananoque and rates
for Port Colborne, effective May 1, 2010, based on a
deemed capital structure containing 40 per cent equity
and an allowed ROE of 8.01 per cent. In non-rebasing
years, customer electricity rates are set using
inflationary factors less an efficiency target under
the OEB's Third-Generation IRM. In April 2010,
FortisOntario received Decisions and Orders from the
OEB with respect to the rate applications. The increase
in base rates was minimal, with an inflationary
increase of 1.3 per cent partially offset by a 1.12 per
cent efficiency target.
- FortisOntario expects to file new electricity
distribution rate applications for harmonized rates for
Fort Erie and Gananoque and rates for Port Colborne
during the third quarter of 2010, for rates effective
January 1, 2011, using 2011 as a forward test year.
- FortisOntario expects to file a new electricity rate
application for Algoma Power during the second quarter
of 2010 for rates effective July 1, 2010, using 2010 as
a forward test year and an anticipated allowed ROE of
9.75 per cent.
--------------------------------------------------------------------------
Belize - Changes made in electricity legislation by the
Electricity Government of Belize and the PUC, and the PUC's June
2008 Final Decision on Belize Electricity's 2008/2009
Rate Application and the PUC's amendment to the June
2008 Final Decision (the "Amendment"), which were based
on the changed legislation, have been judicially
challenged by Belize Electricity in several
proceedings. The judicial process is ongoing with
interim rulings, judgments and appeals. The timing or
likely final outcome of the proceedings is
indeterminable at this time. In 2009, the Supreme Court
of Belize issued an injunction against the Amendment
until Belize Electricity's appeal of the June 2008
Final Decision has been heard in court. The court
appeal of the June 2008 Final Decision was called in
early October 2009 but, after considering some
preliminary matters, the trial judge postponed the case
for a date to be determined.
- In April 2010, Belize Electricity filed its annual
tariff review proceeding application for the annual
tariff period from July 1, 2010 through June 30, 2011.
The application requests changes to various components
of the electric rate, while maintaining the average
electricity rate at BZ44.1 cents per kWh.
--------------------------------------------------------------------------
Caribbean - In February 2010, the ERA approved Caribbean Utilities'
Utilities 2010-2014 Capital Investment Plan at US$98 million for
non-generation expansion expenditures. Additional
generation needs are subject to a competitive bid
process.
--------------------------------------------------------------------------
Fortis Turks - In March 2010, Fortis Turks and Caicos submitted its
and Caicos 2009 annual regulatory filing outlining the Company's
performance in 2009 and its capital expansion plans for
2010.
- In March 2010, Fortis Turks and Caicos filed an
Electricity Rate Review with the Ministry of Works,
Housing and Utilities of the Government of the Turks
and Caicos Islands in accordance with Section 34 of the
Electricity Ordinance. The filing requests an average 7
per cent increase in base customer electricity rates,
effective May 31, 2010. If approved, the rate increase
will be the first rate increase that Fortis Turks and
Caicos has implemented since its inception. The
objectives of the Electricity Rate Review include
setting rates for the various classes of customers
through an Allocated Cost of Service Study, introducing
uniformity in the rate structure throughout the service
territory of Fortis Turks and Caicos and enabling
Fortis Turks and Caicos to start to recover its
December 31, 2009 accumulated regulatory shortfall in
achieving its allowable profit.
--------------------------------------------------------------------------
/T/
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2010 and December 31, 2009.
/T/
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between March 31, 2010 and December 31, 2009
---------------------------------------------------------------------------
Increase/
(Decrease)
Balance Sheet Account ($ millions) Explanation
---------------------------------------------------------------------------
Regulatory assets - 102 The increase was driven by deferrals at
current and long- the Terasen Gas companies
term associated with: (i) a $75 million
change in the fair market value of the
natural gas derivatives; and (ii) the
drawdown of the Commodity Cost
Reconciliation Account as amounts are
being refunded to customers in
current commodity rates.
---------------------------------------------------------------------------
Inventories (40) The decrease was driven by the normal
seasonal reduction of gas in
storage at the Terasen Gas companies,
due to higher consumption during
the winter months.
---------------------------------------------------------------------------
Utility capital assets 48 The increase primarily related to $179
million invested in electricity and gas
systems, partially offset by
amortization and customer contributions
for the three months ended March 31,
2010 and the impact of foreign exchange
on the translation of foreign currency-
denominated utility capital assets.
---------------------------------------------------------------------------
Short-term borrowings (182) The decrease was driven by the
repayment of short-term borrowings by
TGI
with proceeds from an equity injection
from Fortis and lower borrowings at
the Terasen Gas companies due to
seasonality of its operations.
---------------------------------------------------------------------------
Accounts 37 The increase was driven by a $75
payable and million change in the fair market value
accrued charges of the natural gas derivatives at the
Terasen Gas companies, partially offset
by lower amounts owing for purchased
natural gas due to lower natural gas
prices and volumes at the Terasen Gas
companies.
---------------------------------------------------------------------------
Dividends payable 50 The increase was due to the timing of
the declaration of common share
dividends for the first quarter of 2010
and an increase in the quarterly
common share dividend declared from
$0.26 per share to $0.28 per share.
---------------------------------------------------------------------------
Long-term debt and (68) The decrease was driven by a net $29
capital lease million repayment of committed
obligations credit facility borrowings, regularly
(including scheduled debt repayments and the
current portion) impact of foreign exchange on
currency-denominated long-term debt.
---------------------------------------------------------------------------
Shareholders' equity 259 The increase was driven by the issuance
of $250 million five-year fixed rate
reset preference shares in January
2010.
The remainder of the increase was due
to net earnings attributable to
common equity shareholders reported for
the three months ended
March 31, 2010, less common share
dividends, and the issuance of common
shares under the Corporation's share
purchase, dividend reinvestment and
stock option plans, partially offset by
an increase in accumulated other
comprehensive loss and lower non-
controlling interest.
---------------------------------------------------------------------------
/T/
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash for the first quarter of 2010, as compared to the first quarter of 2009, followed by a discussion of the nature of the variances in cash flows quarter over quarter.
/T/
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Summary of Consolidated Cash Flows
(Unaudited)
Quarter Ended March 31
($ millions) 2010 2009 Variance
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Cash, Beginning of Period 85 66 19
Cash Provided by (Used in):
Operating Activities 249 229 20
Investing Activities (176) (210) 34
Financing Activities (65) 9 (74)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents (1) - (1)
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Cash, End of Period 92 94 (2)
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/T/
Operating Activities: Cash flow from operating activities, after working capital adjustments, was $20 million higher quarter over quarter. The increase was primarily due to higher earnings and favourable working capital changes. The favourable working capital changes were driven by: (i) the timing of the declaration of common share dividends for the first quarter of 2010; (ii) favourable changes in the Alberta Electric System Operator ("AESO") charges deferral account at FortisAlberta; and (iii) a decrease in the amount of corporate taxes paid at the Terasen Gas companies and Newfoundland Power, partially offset by unfavourable working capital changes at the Terasen Gas companies, reflecting differences in the commodity cost of natural gas and cost of natural gas charged to customers quarter over quarter.
Investing Activities: Cash used in investing activities was $34 million lower quarter over quarter, driven by lower gross capital expenditures at FortisAlberta, mainly due to lower demand for new services from irrigation customers and lower spending related to equipment, facilities and AESO transmission capital projects.
Financing Activities: Cash used in financing activities was $65 million during the quarter compared to cash provided by financing activities of $9 million during the same quarter in 2009. Lower proceeds from long-term debt, higher common share dividends and higher net repayments under committed credit facilities and short-term borrowings were partially offset by higher proceeds from the issuance of preference shares.
Net repayments of short-term borrowings were $181 million during the first quarter of 2010, $31 million higher than net repayments of $150 million during the same quarter in 2009. The net repayments during the first quarter of 2010 were driven by TGI using proceeds from an equity injection by the Corporation.
In January 2010, Fortis completed a $250 million five-year fixed rate reset preference share offering. The net proceeds of approximately $242 million were used to repay borrowings under the Corporation's committed credit facility and to fund the equity injection into TGI.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease obligations and net (repayments) borrowings under committed credit facilities for the first quarter of 2010 compared to the same quarter of 2009 are summarized in the following tables.
/T/
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Proceeds from Long-Term Debt, Net of Issue
Costs (Unaudited)
Quarter Ended March 31
($ millions) 2010 2009 Variance
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Terasen Gas Companies - 99(1) (99)
FortisAlberta - 99(2) (99)
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Total - 198 (198)
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(1) Issued February 2009, 30-year $100 million 6.55% unsecured debentures
by TGI. The net proceeds were used to repay credit facility borrowings
and repay $60 million 10.75% unsecured debentures that matured in
June 2009.
(2) Issued February 2009, 30-year $100 million 7.06% unsecured debentures.
The net proceeds were used to repay committed credit facility
borrowings and for general corporate purposes.
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Repayments of Long-Term Debt and Capital Lease
Obligations (Unaudited)
Quarter Ended March 31
($ millions) 2010 2009 Variance
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Fortis Properties (14) (2) (12)
Other (2) (4) 2
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Total (16) (6) (10)
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Net (Repayments) Borrowings Under Committed Credit
Facilities (Unaudited)
Quarter Ended March 31
($ millions) 2010 2009 Variance
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FortisAlberta 40 (54) 94
FortisBC (9) 5 (14)
Newfoundland Power 11 30 (19)
Corporate (71) 24 (95)
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Total (29) 5 (34)
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/T/
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 issues are used to repay borrowings under the Corporation's committed credit facility.
Proceeds from the issuance of common shares increased $10 million quarter over quarter, reflecting the impact of the participation by shareholders in the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan. The plan provides participating common shareholders a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.
Common share dividends were $96 million during the first quarter of 2010, up $52 million from the same quarter of 2009. The increase was primarily due to the timing of the declaration of common share dividends for the first quarter of 2010 and an increase in the quarterly common share dividend declared. The dividend declared per common share for the first quarter of 2010 was $0.28, while the dividend declared per common share for the first quarter of 2009 was $0.26.
Preference share dividends increased $2 million quarter over quarter as a result of the dividends associated with the 10 million preference shares that were issued in January 2010.
Contractual Obligations: Consolidated contractual obligations of Fortis over the next five years and for periods thereafter, as of March 31, 2010, are outlined in the following table. A detailed description of the nature of the obligations is provided below and in the MD&A for the year ended December 31, 2009.
/T/
Contractual Obligations
(Unaudited)
Due Due in Due in Due
As at March 31, 2010 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
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Long-term debt 5,433 333 297 771 4,032
Brilliant Terminal Station 61 3 5 5 48
Gas purchase contract obligations
(1) 516 233 157 126 -
Power purchase obligations
FortisBC (2) 2,927 44 89 83 2,711
FortisOntario 496 45 96 100 255
Maritime Electric 50 31 2 2 15
Belize Electricity 310 26 63 61 160
Capital cost 379 15 41 41 282
Joint-use asset and share service
agreements 62 4 6 6 46
Office lease - FortisBC 18 1 4 3 10
Operating lease obligations 143 17 30 26 70
Equipment purchase - Fortis Turks
and Caicos 9 9 - - -
Defined benefit pension funding
contributions (3) 36 18 13 3 2
Other 28 14 8 5 1
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Total 10,468 793 811 1,232 7,632
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(1) Based on index prices as at March 31, 2010
(2) During the first quarter of 2010, FortisBC entered into a contract
with Powerex Corp., a wholly owned subsidiary of BC Hydro, for
fixed-price winter capacity purchases through to February 2016 in an
aggregate amount of approximately US$16 million. If FortisBC brings
any new resources, such as capital or contractual projects, on-line
prior to the expiry of this agreement, FortisBC may terminate this
contract any time after July 1, 2013 with a minimum of three-months
written notice to Powerex Corp.
(3) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than the above estimated amounts pending completion of the next
actuarial valuations for funding purposes, which are expected to be as
follows for the larger defined benefit pension plans:
December 31, 2009 Terasen (covering non-unionized employees)
December 31, 2010 Terasen (covering unionized employees) and FortisBC
December 31, 2011 Newfoundland Power
Other Contractual Obligations:
In prior years, TGVI received non-interest bearing repayable loans from
the federal and provincial governments of $50 million and $25 million,
respectively, in connection with the construction and operation of the
Vancouver Island natural gas pipeline. As approved by the BCUC, these
loans have been recorded as government grants and have reduced the amounts
reported for utility capital assets. The government loans are repayable in
any fiscal year prior to 2012 under certain circumstances and subject to
the ability of TGVI to obtain non-government subordinated debt financing
on reasonable commercial terms. As the loans are repaid and replaced with
non-government loans, utility capital assets and long-term debt will
increase in accordance with TGVI's approved capital structure, as will
TGVI's rate base, which is used in determining customer rates. The
repayment criteria were met in 2009 and TGVI is expected to make an
approximate $4 million repayment on the loans during the second quarter
of 2010. As at March 31, 2010, the outstanding balance of the repayable
government loans was approximately $53 million, with approximately
$4 million classified as current portion of long-term debt. Repayments
of the government loans beyond 2010 are not included in the contractual
obligations table above as the amount and timing of the repayments are
dependent upon the ability of TGVI to replace the government loans with
non-government subordinated debt financing on reasonable commercial terms.
TGVI, however, estimates making payments under the loans of $20 million
in 2012, $14 million over 2013 and 2014 and $15 million thereafter.
Caribbean Utilities has a primary fuel supply contract with a major
supplier and is committed to purchase 80 per cent of the Company's fuel
requirements from this supplier for the operation of Caribbean Utilities'
diesel-powered generating plant. The contract is for three years,
terminating in April 2010. The contract contains an automatic renewal
clause for the years 2010 through 2012. Should any party choose to
terminate the contract within that two-year period, notice must be given
a minimum of one year in advance of the desired termination date. No such
termination notice has been given by either party to date. The quantity
of fuel to be purchased under the contract for 2010 is approximately
25 million imperial gallons.
Fortis Turks and Caicos has a renewable contract with a major supplier
for all of its diesel fuel requirements associated with the generation
of electricity. The approximate fuel requirements under this contract
are 12 million imperial gallons per annum.
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/T/
Capital Structure: The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow 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. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent 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 the utilitites' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
/T/
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Capital Structure
(Unaudited) As at
March 31, December 31,
2010 2009
($ millions) (%) ($ millions) (%)
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Total debt and capital
lease obligations
(net of cash) (1) 5,573 57.5 5,830 60.2
Preference shares (2) 912 9.4 667 6.9
Common shareholders'
equity 3,212 33.1 3,193 32.9
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Total (3) 9,697 100.0 9,690 100.0
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(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity
(3) Excludes amounts related to non-controlling interests
/T/
The change in the capital structure was driven by the issuance of $250 million preference shares in January 2010; increased common shares outstanding, reflecting the impact of the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan; and the repayment of credit facility borrowings with proceeds from the preference share issue.
The Corporation's credit ratings are as follows:
/T/
Standard & Poor's A- (long-term corporate and unsecured
debt credit rating)
DBRS BBB(high) (unsecured debt credit rating)
/T/
The credit ratings reflect the diversity of the operations of Fortis, 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 and the continued focus of Fortis on pursuing the acquisition of stable regulated utilities.
Capital Program: The Corporation's principal businesses of regulated gas and electricity distribution are capital intensive. 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.
During the first quarter of 2010, gross consolidated capital expenditures were $188 million. A breakdown of gross capital expenditures by segment for the first quarter of 2010 is provided in the following table.
/T/
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Gross Capital Expenditures (Unaudited) (1)
Quarter Ended March 31, 2010
($ millions)
--------------------------------------------------------------------------
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Other Total
Regula- Regu- Regu-
Tera- ted lated lated Non-
sen New- Utili- Utili- Utili- Regula-
Gas Fortis found- ties- ties- ties- ted- Fortis
Compa- Alberta Fortis- land Cana- Cana- Carib- Utility Proper-
nies (2) BC Power dian dian bean (3) ties Total
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50 64 26 17 8 165 17 1 5 188
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(1)Relates to utility capital assets, income producing properties and
intangible assets and includes capital expenditures associated with
assets under construction. Includes asset removal and site restoration
expenditures, net of salvage proceeds, for those utilities where such
expenditures are permissible in rate base in 2010. Excludes capitalized
non-cash equity component of the Allowance for Funds Used During
Construction.
(2)Includes payments made to AESO for investment in transmission capital
projects
(3)Includes non-regulated utility and corporate capital expenditures
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/T/
There has been no material change in forecast gross consolidated capital expenditures for 2010 from the approximate $1.1 billion forecast as was disclosed in the MD&A for the year ended December 31, 2009. 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 are no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those disclosed in the MD&A for the year ended December 31, 2009.
Over the five-year period 2010 through 2014, consolidated gross capital expenditures are expected to approach $5 billion. Approximately 70 per cent of the capital spending is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta and FortisBC, and 27 per cent of the capital spending is expected to be incurred at the Regulated Gas Utilities. Approximately 3 per cent is expected to be incurred at the non-regulated operations. Capital expenditures at the Regulated Utilities are subject to regulatory approval.
Cash Flow Requirements: At the operating 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 flow 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 issues.
The Corporation's ability to service its debt obligations and pay dividends on its common 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 which 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 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 credit facility may be required from time to time to support the servicing of debt and payment of dividends.
As at March 31, 2010, management expects consolidated long-term debt maturities and repayments to average approximately $280 million annually over the next five years. 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 a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application in June 2008, Belize Electricity does not meet certain debt covenant financial ratios related to loans with the International Bank for Reconstruction and Development and the Caribbean Development Bank totalling $6 million (BZ$11 million) as at March 31, 2010.
As the hydroelectric assets and water rights of the Exploits Partnership had been provided as security for the Exploits Partnership term loan, the expropriation of such assets and rights by the Government of Newfoundland and Labrador constituted an event of default under the loan. The term loan is without recourse to Fortis and was approximately $59 million as at March 31, 2010 (December 31, 2009 - $59 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor, a Crown corporation, acting as agent for the Government of Newfoundland and Labrador with respect to the expropriation matters.
Except for the debt at Belize Electricity and the Exploits Partnership, as discussed above, Fortis and its subsidiaries were in compliance with debt covenants as at March 31, 2010 and are expected to remain compliant throughout 2010.
As at March 31, 2010, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which $1.6 billion was unused, including $547 million unused under the Corporation's $600 million committed revolving credit facility. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 25 per cent of these facilities. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which currently have maturities between 2011 and 2013.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
/T/
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Credit Facilities
(Unaudited) As at
December
Corporate Regulated Fortis March 31, 31,
and Other Utilities Properties 2010 2009
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Total credit
facilities 645 1,493 13 2,151 2,153
Credit facilities
utilized:
Short-term
borrowings - (233) - (233) (415)
Long-term debt
(including
current portion) (53) (113) - (166) (208)
Letters of credit
outstanding (1) (115) (1) (117) (100)
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Credit facilities
unused 591 1,032 12 1,635 1,430
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/T/
As at March 31, 2010 and December 31, 2009, 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.
Regulated Utilities
In February 2010, Maritime Electric renewed its $50 million unsecured committed revolving credit facility, which matures annually in March.
In March 2010, FortisBC negotiated an extension of its $150 million unsecured committed revolving credit facility, of which $100 million now matures May 2013 and the remaining $50 million now matures May 2011. The amended credit facility agreement is expected to be finalized during the second quarter of 2010.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments. The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt and preference shares were as follows.
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Financial Instruments
(Unaudited) As at
March 31, 2010 December 31, 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Long-term debt, including
current portion (1) 5,433 5,921 5,502 5,906
Preference shares,
classified as debt (2) 320 357 320 348
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(1)Carrying value as at March 31, 2010 excludes unamortized deferred
financing costs of $38 million (December 31, 2009 - $39 million) and
capital lease obligations of $37 million (December 31, 2009 - $37
million).
(2)Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was
$595 million as at March 31, 2010 (December 31, 2009 - carrying value
$347 million; fair value $356 million).
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/T/
Risk Management: The Corporation's earnings from, and net investment in, self-sustaining foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above 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 or a currency pegged to the US dollar. Belize Electricity's reporting currency is the Belizean dollar, while the reporting currency of Caribbean Utilities, FortisUS Energy Corporation, Belize Electric Company Limited, and Fortis Turks and Caicos is the US dollar. The Belizean dollar is pegged to the US dollar at BZ$2.00=US$1.00.
As at March 31, 2010, all of the Corporation's US$390 million (December 31, 2009 - US$390 million) corporately held long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings designated as hedges, are recorded in other comprehensive income and serve to help offset unrealized foreign currency gains and losses on the foreign net investments, which are also recorded in other comprehensive income. As at March 31, 2010, the Corporation had approximately US$179 million (December 31, 2009 - US$174 million) in foreign net investments remaining to be hedged.
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes.
The following table summarizes the valuation of the Corporation's consolidated derivative financial instruments.
/T/
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Derivative Financial
Instruments (Unaudited) As at
March 31,
2010 December 31, 2009
Estimated
Carrying Fair Carrying Estimated
Term to Number Value Value Value Fair Value
Maturity of ($ ($ ($ ($
Liability (years)Contracts millions) millions) millions) millions)
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Interest less than
rate swap 1 1 - - - -
Foreign
exchange
forward
contracts 1 to 2 2 - - - -
Natural gas
derivatives:
Swaps and
options Up to 5 186 (194) (194) (119) (119)
Gas
purchase
contract
premiums Up to 2 24 (3) (3) (3) (3)
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/T/
The interest rate swap is held by Fortis Properties and is designated as a hedge of the cash flow risk related to floating-rate long-term debt and matures in October 2010. The effective portion of changes in the value of the interest rate swap at Fortis Properties is recorded in other comprehensive income.
The foreign exchange forward contracts are held by the Terasen Gas companies. During the first quarter of 2010, TGI entered into a foreign exchange forward contract to hedge the cash flow risk related to approximately US$15 million required to be paid under a contact for the implementation of a customer information system. TGVI also hedges the cash flow risk related to approximately US$7 million remaining to be paid under a contract for the construction of a liquefied natural gas storage facility.
The natural gas derivatives are held by the Terasen Gas companies and are used to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The price risk-management strategy of the Terasen Gas companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies.
The changes in the fair values of the foreign exchange forward contracts and natural gas derivatives are deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates. The fair values of the foreign exchange forward contracts were recorded in accounts payable as at March 31, 2010 and accounts receivable as at December 31, 2009. The fair values of the natural gas derivatives were recorded in accounts payable as at March 31, 2010 and as at December 31, 2009.
The interest rate swap is valued at the present value of future cash flows based on published forward future interest rate curves. The foreign exchange forward contracts are valued using the present value of cash flows based on a market foreign exchange rate and the foreign exchange forward rate curve. The natural gas derivatives are valued 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 foreign exchange forward contracts and natural gas derivatives are estimates of the amounts the Terasen Gas companies would have to receive or pay if forced to settle all 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
As at March 31, 2010, 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
A detailed discussion of the Corporation's significant business risks is provided in the MD&A for the year ended December 31, 2009. There were no changes in the Corporation's significant business risks during the first quarter of 2010 from those disclosed in the MD&A for the year ended December 31, 2009, except for those described below.
Capital Resources and Liquidity Risk - Credit Ratings: Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term. During the first quarter of 2010, there was no change in the credit ratings for the Corporation and its currently rated subsidiaries. However, Moody's confirmed its existing credit ratings for TGVI, FortisAlberta and Newfoundland Power. DBRS also confirmed its existing credit rating for FortisAlberta.
Defined Benefit Pension Plan Performance and Funding Requirements: As at March 31, 2010, the fair value of the Corporation's consolidated defined benefit pension plan assets was $681 million, up $20 million, or 3 per cent, from $661 million as at December 31, 2009.
CHANGES IN ACCOUNTING POLICIES AND STANDARDS
Effective January 1, 2010, as required by the regulator, FortisAlberta began capitalizing to utility capital assets a portion of the amortization of utility capital assets, such as tools and vehicles, used in the construction of other assets. During the first quarter of 2010, amortization of $1 million was capitalized.
Effective January 1, 2010, as a result of the BCUC-approved NSAs related to 2010 and 2011 revenue requirements, the Terasen Gas companies adopted the following new accounting policies:
/T/
(i) Asset removal costs are now recorded in operating expense on the
consolidated statement of earnings. The annual amount of such costs
approved for recovery in customer rates in 2010 is approximately $8
million. Actual costs incurred in excess of or below the approved
amount are to be recorded in a regulatory deferral account for
recovery from, or refund to, customers in future rates, beginning
in 2012. Removal costs are direct costs incurred by the Terasen Gas
companies in taking assets out of service, whether through actual
removal of the assets or through the disconnection of the assets from
the transmission or distribution system. During the first quarter of
2010, approximately $2 million of actual asset removal costs was
recorded in operating expense. Prior to January 1, 2010, asset
removal costs were recorded against accumulated amortization on
the consolidated balance sheet.
ii. Contributions in aid of construction ("CIACs") are now amortized to
revenue. During the first quarter of 2010, approximately $3 million of
CIACs was amortized to revenue on the consolidated statement of
earnings. Prior to January 1, 2010, amortization of CIACs was recorded
against amortization expense on the consolidated statement of earnings.
iii.Gains and losses on the sale or disposal of utility capital assets are
now recorded in a regulatory deferral account on the consolidated
balance sheet for recovery from, or refund to, customers in future
rates, subject to regulatory approval. During the first quarter of
2010, approximately $3 million of losses were deferred and recorded as
a regulatory asset on the consolidated balance sheet. Prior to
January 1, 2010, gains and losses on the sale or disposal of utility
capital assets were recorded against accumulated amortization.
iv. Amortization of utility capital and intangible assets now commences the
month after the assets are available for use. Prior to January 1, 2010,
amortization commenced the year following when the assets became
available for use. During 2010, additional amortization expense of
approximately $2 million is expected to be incurred, due to the change
in commencement of amortization of utility capital and intangible
assets.
/T/
Business Combinations
Effective January 1, 2010, the Corporation early adopted the new Canadian Institute of Chartered Accountants Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-Controlling Interests. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of an acquiree in a business combination results in a different calculation of goodwill with respect to acquisitions on or after January 1, 2010. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals by the acquirer. The adoption of Section 1582 did not have a material impact on the Corporation's interim unaudited consolidated financial statements for the first quarter of 2010.
Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of Sections 1601 and 1602 resulted in non-controlling interests being presented as components of equity, rather than as liabilities, on the consolidated balance sheet. Also, net earnings and components of other comprehensive income attributable to the owners of the parent company and to non-controlling interests are now separately disclosed on the consolidated statement of earnings and consolidated statement of comprehensive income.
FUTURE ACCOUNTING CHANGES
Transition to International Financial Reporting Standards
A detailed discussion of the Corporation's transition to International Financial Reporting Standards ("IFRS") is provided in the MD&A for the year ended December 31, 2009. The Corporation is still unable to fully determine the impact on its future financial position and results of operations of the transition to IFRS, particularly as it relates to the accounting for rate-regulated activities. Completion of the Rate-Regulated Activities project of the International Accounting Standard Board ("IASB") has been delayed based on comments received in response to the IASB's July 2009 Exposure Draft on Rate-Regulated Activities and a decision by the IASB to conduct further research. Project direction and timeline remain uncertain and may not be known for several months. Once a decision is made by the IASB regarding the Rate-Regulated Activities project, Fortis will be in a position to finalize the impact the transition to IFRS is expected to have on the Corporation's January 1, 2010 opening IFRS balance sheet, as well as on its future financial reporting.
During the first quarter of 2010, there were no significant changes in the Corporation's assessment of accounting for rate-regulated activities under IFRS or accounting policy decisions and impacts from those disclosed in the MD&A for the year ended December 31, 2009, except as described below.
Accounting Policy Decisions and Impacts
Property, Plant and Equipment and Intangibles: It is anticipated that during the second quarter of 2010, the IASB will issue a final amendment to IFRS 1, First-time Adoption of International Financial Reporting Standards ("IFRS1"), to provide a transitional exemption for qualifying rate-regulated entities that will allow them to use the carrying value of property, plant and equipment and intangible assets under Canadian GAAP as deemed cost upon transition to IFRS. The Corporation's rate-regulated utilities are expecting to avail of this transitional exemption.
Business Combinations: The Corporation currently intends to avail of the elective exemption under IFRS 1 with respect to IFRS 3, Business Combinations ("IFRS 3"), by prospectively applying IFRS 3 to business combinations that occurred on or after October 1, 2009 or, more specifically, by restating the October 2009 acquisition of Algoma Power to comply with IFRS 3. Restating the acquisition is not expected to have a material impact on the Corporation's consolidated financial statements upon transition to IFRS.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period 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 first quarter of 2010 from those disclosed in the Corporation's MD&A for the year ended December 31, 2009, except for that described below related to capital asset amortization.
Capital Asset Amortization: As a result of a recent depreciation study and BCUC-approved NSAs related to TGI and TGVI's 2010 and 2011 revenue requirements, amortization expense at the Terasen Gas companies is expected to increase in 2010, reflecting an increase in the composite depreciation rate to 2.79 per cent for 2010 from 2.63 per cent for 2009. The increase in amortization has been approved for recovery in current customer delivery rates.
Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course 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. There were no material changes in the Corporation's contingent liabilities from those disclosed in the MD&A for the year ended December 31, 2009.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2008 through March 31, 2010. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements which, in the opinion of management, have been prepared in accordance with Canadian GAAP and as required by utility regulators. The timing of the recognition of certain assets, liabilities, revenue and expenses, as a result of regulation, may differ from that otherwise expected using Canadian GAAP for non-regulated entities. The differences and nature of regulation are disclosed in Notes 2 and 4 to the Corporation's 2009 annual audited consolidated financial statements. The quarterly financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
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Summary of Quarterly Results (Unaudited)
Net Earnings
Attributable to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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March 31, 2010 1,076 100 0.58 0.56
December 31, 2009 1,018 81 0.48 0.46
September 30, 2009 664 36 0.21 0.21
June 30, 2009 754 53 0.31 0.31
March 31, 2009 1,202 92 0.54 0.52
December 31, 2008 1,181 76 0.48 0.46
September 30, 2008 727 49 0.31 0.31
June 30, 2008 848 29 0.19 0.18
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A summary of the past eight quarters reflects the Corporation's continued organic growth and 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 and mid-stream cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Fortis companies, seasonality may vary. Most of the annual earnings of the Terasen Gas companies are generated in the first and fourth quarters. Financial results from May 1, 2009 have been impacted, as expected, by the loss of revenue and earnings subsequent to the expiration, in April 2009, of the water rights of the Rankine hydroelectric generating facility in Ontario. Financial results for the fourth quarter ended December 31, 2009 reflected the favourable cumulative retroactive impact associated with an increase in the allowed ROEs for 2009 for FortisAlberta and TGI, and an increase in the equity component at FortisAlberta. Financial results for the fourth quarter ended December 31, 2008 included two additional months of contribution from Caribbean Utilities, resulting from a change in the utility's fiscal year end. Financial results for the second quarter ended June 30, 2008 reflected a $13 million unfavourable impact to Fortis of a charge recorded at Belize Electricity as a result of the June 2008 regulatory rate decision. To a lesser degree, financial results from November 2008 were impacted by the acquisition of the Sheraton Hotel Newfoundland, from April 2009 by the acquisition of the Holiday Inn Select Windsor and from October 2009 by the acquisition of Algoma Power.
March 2010/March 2009 - Net earnings attributable to common equity shareholders were $100 million, or $0.58 per common share, for the first quarter of 2010 compared to earnings of $92 million, or $0.54 per common share, for the first quarter of 2009. The increase in earnings was led by the Terasen Gas companies associated with an increase in the allowed ROEs and equity component. Results also reflected: (i) improved performance at FortisAlberta, associated with an increase in the allowed ROE and equity component combined with growth in electrical infrastructure investment and customers; and (ii) increased earnings at Newfoundland Power, mainly due to growth in electrical infrastructure investment, increased electricity sales and timing differences favourably impacting operating expenses during the quarter. Earnings' growth was tempered by: (i) lower earnings' contribution from non-regulated hydroelectric generation operations due to loss of earnings subsequent to the expiration of the Rankine water rights in April 2009; (ii) lower contribution from Caribbean Regulated Electric Utilities associated with the unfavourable impact of foreign exchange translation, and earnings in the first quarter of 2009 including an approximate $1 million one-time gain; and (iii) higher preference share dividends.
December 2009/December 2008 - Net earnings attributable to common equity shareholders were $81 million, or $0.48 per common share, for the fourth quarter of 2009 compared to earnings of $76 million, or $0.48 per common share, for the fourth quarter of 2008. Fourth quarter results for 2009 were favourably impacted by a one-time $3 million adjustment to future income taxes related to prior periods at FortisOntario and were unfavourably impacted by a one-time $5 million after-tax provision for additional costs related to the conversion of Whistler customer appliances from propane to natural gas. Fourth quarter results for 2008 included two additional months of earnings' contribution from Caribbean Utilities (August and September 2008) of approximately $2 million due to a change in the utility's fiscal year end. Excluding the above one-time items, earnings increased $9 million quarter over quarter. The increase was driven by: (i) the approximate $10 million cumulative retroactive impact in the fourth quarter of 2009 associated with the increase in the allowed ROEs for 2009 for FortisAlberta and TGI, and an increase in the equity component at FortisAlberta; and (ii) a change in depreciation estimates at Fortis Turks and Caicos, which favourably impacted amortization expense for the fourth quarter of 2009. The increase was partially offset by lower earnings' contribution from non-regulated hydroelectric generation operations due to loss of earnings subsequent to the expiration of the Rankine water rights in April 2009.
September 2009/September 2008 - Net earnings attributable to common equity shareholders were $36 million, or $0.21 per common share, for the third quarter of 2009 compared to earnings of $49 million, or $0.31 per common share, for the third quarter of 2008. Third quarter 2008 results included a tax reduction of approximately $7.5 million associated with the settlement of historical corporate tax matters at Terasen and a $4.5 million recovery of future income taxes, which was previously expensed during the first half of 2008 at FortisAlberta. Earnings were $1 million lower quarter over quarter, excluding the above one-time tax reductions. The impact of lower effective corporate income taxes at the Terasen Gas companies and growth in electrical infrastructure investment and higher net transmission revenue at FortisAlberta was more than offset by lower earnings from non-regulated hydroelectric generation and lower earnings at Newfoundland Power. The decrease in earnings from non-regulated hydroelectric generation operations was primarily associated with the loss of earnings subsequent to the expiration of the Rankine water rights in April 2009. Lower earnings at Newfoundland Power were largely associated with higher operating expenses and amortization costs.
June 2009/June 2008 - Net earnings attributable to common equity shareholders were $53 million, or $0.31 per common share, for the second quarter of 2009 compared to earnings of $29 million, or $0.19 per common share, for the second quarter of 2008. Results for the second quarter of 2008 included one-time charges of approximately $15 million pertaining to Belize Electricity, associated with the June 2008 regulatory rate decision, and FortisOntario, associated with the repayment, during the second quarter of 2008, of an interconnection agreement-related refund received in the fourth quarter of 2007. Excluding these one-time charges, earnings increased $9 million quarter over quarter, driven by lower corporate income taxes and growth in electrical infrastructure investment at FortisAlberta, and lower corporate income taxes at the Terasen Gas companies. The increase was partially offset by lower earnings' contribution from non-regulated hydroelectric generation operations primarily associated with the loss of earnings subsequent to the expiration of the Rankine water rights in April 2009.
SUBSEQUENT EVENT
In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.
OUTLOOK
The Corporation's significant capital program, which is expected to be approximately $1.1 billion in 2010 and approach $5 billion over the five-year period from 2010 through 2014, should drive growth in earnings and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing on strategic opportunities to acquire regulated electric and natural gas utilities in the United States, Canada and the Caribbean. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at April 29, 2010, the Corporation had issued and outstanding 172.2 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; and 10.0 million First Preference Shares, Series H. Only the common shares of the Corporation have voting rights.
The number of common shares of Fortis that would be issued if all outstanding stock options, convertible debt and First Preference Shares, Series C and E were converted as at April 29, 2010 is as follows:
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Potential Conversion of Securities into Common Shares
(Unaudited)
As at April 29, 2010 Number of
Common Shares
Security (millions)
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Stock Options 5.4
Convertible Debt 1.4
First Preference Shares, Series C 4.7
First Preference Shares, Series E 7.6
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Total 19.1
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Additional information, including the Fortis 2009 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.
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Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31, December 31,
2010 2009
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(Note 2)
ASSETS
Current assets
Cash and cash equivalents $92 $85
Accounts receivable 604 595
Prepaid expenses 19 16
Regulatory assets (Note 5) 304 223
Inventories (Note 6) 138 178
Future income taxes 13 29
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1,170 1,126
Other assets 170 174
Regulatory assets (Note 5) 764 743
Future income taxes 21 17
Utility capital assets 7,744 7,696
Income producing properties 560 559
Intangible assets 276 279
Goodwill 1,555 1,560
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$12,260 $12,154
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 19) $233 $415
Accounts payable and accrued charges 889 852
Dividends payable 53 3
Income taxes payable 16 23
Regulatory liabilities (Note 5) 45 53
Current installments of long-term debt and
capital lease obligations (Note 7) 336 224
Future income taxes 9 24
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1,581 1,594
Deferred credits 299 295
Regulatory liabilities (Note 5) 455 436
Future income taxes 587 570
Long-term debt and capital lease
obligations (Note 7) 5,096 5,276
Preference shares 320 320
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8,338 8,491
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Shareholders' equity
Common shares (Note 8) 2,520 2,497
Preference shares (Note 9) 592 347
Contributed surplus 11 11
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (Note
11) (91) (83)
Retained earnings 767 763
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3,804 3,540
Non-controlling interest 118 123
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3,922 3,663
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$12,260 $12,154
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Contingent liabilities and commitments (Note 20)
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
2010 2009
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(Note 2)
Revenue $1,076 $1,202
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Expenses
Energy supply costs 552 707
Operating 202 193
Amortization 97 91
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851 991
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Operating income 225 211
Finance charges (Note 13) 90 88
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Earnings before corporate taxes 135 123
Corporate taxes (Note 14) 28 25
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Net earnings $107 $98
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Net earnings attributable to:
Non-controlling interest $1 $2
Preference equity shareholders 6 4
Common equity shareholders 100 92
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$107 $98
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Earnings per common share (Note 8)
Basic $0.58 $0.54
Diluted $0.56 $0.52
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See accompanying Notes to Interim Consolidated Financial
Statements
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Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2010 2009
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(Note 2)
Balance at beginning of period $763 $634
Net earnings attributable to common and preference
equity shareholders 106 96
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869 730
Dividends on common shares (96) (44)
Dividends on preference shares classified as equity (6) (4)
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Balance at end of period $767 682
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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
2010 2009
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(Note 2)
Net earnings $107 $98
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Other comprehensive income (loss)
Unrealized foreign currency translation (losses) gains on
net investments in self-sustaining foreign operations (20) 24
Gains (losses) on hedges of net investments in self-
sustaining foreign operations 14 (18)
Corporate tax (expense) recovery (2) 3
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Change in unrealized foreign currency translation (losses)
gains, net of hedging activitiesand tax (Note 11) (8) 9
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Comprehensive income $99 $107
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Comprehensive income attributable to:
Non-controlling interest $1 $2
Preference equity shareholders 6 4
Common equity shareholders 92 101
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$99 $107
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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
2010 2009
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(Note 2)
Operating activities
Net earnings $107 $98
Items not affecting cash:
Amortization - utility capital assets and income
producing properties 86 79
Amortization - intangible assets 11 11
Amortization - other - 1
Future income taxes (3) 3
Other (1) (3)
Change in long-term regulatory assets and
liabilities 4 9
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204 198
Change in non-cash operating working capital 45 31
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249 229
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Investing activities
Change in other assets and deferred credits 2 (7)
Capital expenditures - utility capital assets (179) (210)
Capital expenditures - income producing properties (6) (5)
Capital expenditures - intangible assets (3) (4)
Contributions in aid of construction 10 16
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(176) (210)
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Financing activities
Change in short-term borrowings (181) (150)
Proceeds from long-term debt, net of issue costs - 198
Repayments of long-term debt and capital lease
obligations (16) (6)
Net (repayments) borrowings under committed credit
facilities (29) 5
Issue of common shares, net of costs 23 13
Issue of preference shares, net of costs 242 -
Dividends
Common shares (96) (44)
Preference shares (6) (4)
Subsidiary dividends paid to non-controlling
interest (2) (3)
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(65) 9
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Effect of exchange rate changes on cash and cash
equivalents (1) -
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Change in cash and cash equivalents 7 28
Cash and cash equivalents, beginning of period 85 66
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Cash and cash equivalents, end of period $92 $94
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Supplementary information to Consolidated Statements
of Cash Flows (Note 16)
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2010 and 2009
(unless otherwise stated) (Unaudited)
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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 Corporation's long-term objectives. Each reporting segment operates as an autonomous unit, assumes profit and loss responsibility and is accountable for its own resource allocation.
The following summary describes the operations included in each of the Corporation's reportable segments.
REGULATED UTILITIES
The following summary describes the Corporation's interests in regulated gas and electric utilities in Canada and the Caribbean by utility:
Regulated Gas Utilities - Canadian
Terasen Gas Companies: Includes Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI").
TGI is the largest distributor of natural gas in British Columbia, serving primarily residential, commercial and industrial customers in a service area that extends from Vancouver to the Fraser Valley and the interior of British Columbia.
TGVI owns and operates the natural gas transmission pipeline from the Greater Vancouver area across the Georgia Strait to Vancouver Island and the distribution system on Vancouver Island and along the Sunshine Coast of British Columbia, serving primarily residential, commercial and industrial customers.
In addition to providing transmission and distribution services to customers, TGI and TGVI also obtain natural gas supplies on behalf of most residential and commercial customers. Gas supplies are sourced primarily from northeastern British Columbia and, through TGI's Southern Crossing Pipeline, from Alberta.
TGWI owns and operates the natural gas distribution system in the Resort Municipality of Whistler, British Columbia, which provides service mainly to residential and commercial customers.
Regulated Electric Utilities - Canadian
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a. FortisAlberta: FortisAlberta owns and operates the electricity
distribution system in a substantial portion of southern and central
Alberta.
b. FortisBC: Includes FortisBC Inc., an integrated electric utility
operating in the southern interior of British Columbia. FortisBC Inc.
owns four hydroelectric generating facilities with a combined capacity
of 223 megawatts ("MW"). Included with the FortisBC component of
the Regulated Electric Utilities - Canadian segment are the operating,
maintenance and management services relating to the 493-MW Waneta
hydroelectric generating facility owned by Teck Cominco Metals Ltd.,
the 149-MW Brilliant hydroelectric plant and 120-MW Brilliant
expansion plant, both owned by Columbia Power Corporation and
the Columbia Basin Trust ("CPC/CBT"), the 185-MW Arrow Lakes
hydroelectric plant owned by CPC/CBT and the distribution system owned
by the City of Kelowna.
c. Newfoundland Power: Newfoundland Power is the principal distributor of
electricity in Newfoundland. Newfoundland Power has an installed
generating capacity of 140 MW, of which 97 MW is hydroelectric
generation.
d. Other Canadian: Includes Maritime Electric and FortisOntario. Maritime
Electric is the principal distributor of electricity on Prince Edward
Island. Maritime Electric also maintains on-Island generating
facilities with a combined capacity of 150 MW. FortisOntario provides
integrated electric utility service to customers in Fort Erie,
Cornwall, Gananoque, Port Colborne and the District of Algoma in
Ontario. FortisOntario's operations include Canadian Niagara
Power Inc. ("Canadian Niagara Power"), Cornwall Street Railway, Light
and Power Company, Limited and, as of October 2009, Algoma Power Inc.
("Algoma Power"). Included in Canadian Niagara Power's accounts is the
operation of the electricity distribution business of Port
Colborne Hydro Inc., which has been leased from the City of Port
Colborne under a ten-year lease agreement that expires in April
2012. FortisOntario also owns a 10 per cent interest in each of
Westario Power Inc., Rideau St. Lawrence Holdings Inc. and Grimsby
Power Inc., three regional electric distribution companies.
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Regulated Electric Utilities - Caribbean
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a. Belize Electricity: Belize Electricity is the principal distributor of
electricity in Belize, Central America. The Company has an installed
generating capacity of 34 MW. Fortis holds an approximate 70 per cent
controlling ownership interest in Belize Electricity.
b. Caribbean Utilities: Caribbean Utilities is the sole provider of
electricity on Grand Cayman, Cayman Islands. The Company has an
installed generating capacity of 153 MW. Fortis holds an approximate 59
per cent controlling ownership interest in Caribbean Utilities.
Caribbean Utilities is a public company traded on the Toronto Stock
Exchange (TSX:CUP.U).
c. Fortis Turks and Caicos: Includes P.P.C. Limited and Atlantic Equipment
& Power (Turks and Caicos) Ltd. Fortis Turks and Caicos is the
principal distributor of electricity in the Turks and Caicos Islands.
The Company has a combined diesel-powered generating capacity of 54 MW.
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NON-REGULATED - FORTIS GENERATION
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a. Belize: Operations consist of the 25-MW Mollejon, the 7-MW Chalillo
and, as of March 2010, the 19-MW Vaca hydroelectric generating
facilities in Belize. All of the output of these facilities is sold
to Belize Electricity under 50-year power purchase agreements expiring
in 2055 and 2060. The hydroelectric generation operations in Belize
are conducted through the Corporation's indirect wholly owned
subsidiary Belize Electric Company Limited ("BECOL") under a franchise
agreement with the Government of Belize.
b. Ontario: Includes six small hydroelectric generating stations in
eastern Ontario with a combined capacity of 8 MW and a 5-MW gas-fired
cogeneration plant in Cornwall. The 75 MW of water-right entitlement
associated with the Rankine hydroelectric generating facility at
Niagara Falls expired on April 30, 2009, at the end of a 100-year term.
c. Central Newfoundland: Through the Exploits River Hydro Partnership (the
"Exploits Partnership"), a partnership between the Corporation, through
its wholly owned subsidiary Fortis Properties, and AbitibiBowater Inc.
("Abitibi"), 36 MW of additional capacity was developed and installed
at two of Abitibi's hydroelectric generating plants in central
Newfoundland. Fortis Properties holds directly a 51 per cent interest
in the Exploits Partnership and Abitibi holds the remaining 49 per cent
interest. Effective February 12, 2009, Fortis discontinued the
consolidation method of accounting for its investment in the Exploits
Partnership due to the expropriation by the Government of Newfoundland
and Labrador of Abitibi's hydroelectric assets and water rights in
Newfoundland including those of the Exploits Partnership. The Exploits
Partnership sold its output to Newfoundland and Labrador Hydro under a
30-year power purchase agreement expiring in 2033.
d. British Columbia: Includes the 16-MW run-of-river Walden hydroelectric
power plant near Lillooet, British Columbia. The plant sells its
entire output to BC Hydro under a long-term contract expiring in 2013.
e. Upper New York State: Includes the operations of four hydroelectric
generating stations in Upper New York State, with a combined capacity
of approximately 23 MW, operating under licences from the U.S. Federal
Energy Regulatory Commission. Hydroelectric generation operations in
Upper New York State are conducted through the Corporation's indirect
wholly owned subsidiary FortisUS Energy Corporation
("FortisUS Energy").
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NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 21 hotels, comprised of more than 4,100 rooms, in eight Canadian provinces and approximately 2.8 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. This segment includes corporate finance charges, including interest on debt incurred directly by Fortis and Terasen Inc. ("Terasen") and dividends on preference shares classified as long-term liabilities; dividends on preference shares classified as equity; other corporate expenses, including Fortis and Terasen corporate operating costs, net of recoveries from subsidiaries; interest and miscellaneous revenue; and corporate income taxes.
Also included in the Corporate and Other segment are the financial results of CustomerWorks Limited Partnership ("CWLP"). CWLP is a non-regulated shared-services business in which Terasen holds a 30 per cent interest. CWLP operates in partnership with Enbridge Inc. and provides customer service contact, meter reading, billing, credit, support and collection services to the Terasen Gas companies and several smaller third parties. CWLP's financial results are recorded using the proportionate consolidation method of accounting. The financial results of Terasen Energy Services Inc. ("TES") are also reported in the Corporate and Other segment. TES is a non-regulated wholly owned subsidiary of Terasen that provides alternative energy solutions.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 2009 annual audited consolidated financial statements. 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. Most of the annual earnings of the Terasen Gas companies are generated in the first and fourth quarters due to seasonality of the business. Given the diversified group of companies, seasonality may vary.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") for interim financial statements, following the same accounting policies and methods as those used in preparing the Corporation's 2009 annual audited consolidated financial statements, except as described below.
Effective January 1, 2010, as required by the regulator, FortisAlberta began capitalizing to utility capital assets a portion of the amortization of utility capital assets, such as tools and vehicles, used in the construction of other assets. During the three months ended March 31, 2010, amortization of $1 million was capitalized.
Effective January 1, 2010, as a result of the British Columbia Utilities Commission ("BCUC")-approved Negotiated Settlement Agreements ("NSAs") related to 2010 and 2011 revenue requirements, the Terasen Gas companies adopted the following new accounting policies:
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i. Asset removal costs are now recorded in operating expense on the
consolidated statement of earnings. The annual amount of such costs
approved for recovery in customer rates in 2010 is approximately $8
million. Actual costs incurred in excess of or below the approved
amount are to be recorded in a regulatory deferral account for
recovery from, or refund to, customers in future rates, beginning in
2012. Removal costs are direct costs incurred by the Terasen Gas
Companies in taking assets out of service, whether through actual
removal of the assets or through the disconnection of the assets
from the transmission or distribution system. During the three months
ended March 31, 2010,
approximately $2 million of actual asset removal costs was recorded in
operating expense. Prior to January 1, 2010, asset removal costs were
recorded against accumulated amortization on the consolidated balance
sheet.
ii. Contributions in aid of construction ("CIACs") are now amortized to
revenue. During the three months ended March 31, 2010, approximately
$3 million of CIACs was amortized to revenue on the consolidated
statement of earnings. Prior to January 1, 2010, amortization of CIACs
was recorded against amortization expense on the consolidated
statement of earnings.
iii.Gains and losses on the sale or disposal of utility capital assets are
now recorded in a regulatory deferral account on the consolidated
balance sheet for recovery from, or refund to, customers in future
rates, subject to regulatory approval. During the three months ended
March 31, 2010, approximately $3 million of losses were deferred and
recorded as a regulatory asset on the consolidated balance sheet.
Prior to January 1, 2010, gains and losses on the sale or disposal of
utility capital assets were recorded against accumulated amortization.
iv. Amortization of utility capital and intangible assets now commences
the month after the assets are available for use. Prior to
January 1, 2010, amortization commenced the year following when the
assets became available for use. During 2010, additional amortization
expense of approximately $2 million is expected to be incurred, due
to the change in commencement of amortization of utility capital
and intangible assets.
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Effective January 1, 2010, the Corporation adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Business Combinations
Effective January 1, 2010, the Corporation early adopted the new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements, and Section 1602,
Non-Controlling Interests. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of an acquiree in a business combination results in a different calculation of goodwill with respect to acquisitions on or after January 1, 2010. Such changes include the expensing of acquisition-related costs incurred during a business acquisition, rather than recording them as a capital transaction, and the disallowance of recording restructuring accruals by the acquirer. The adoption of Section 1582 did not have a material impact on the Corporation's interim consolidated financial statements for the three months ended March 31, 2010.
Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The adoption of Sections 1601 and 1602 resulted in non-controlling interests being presented as components of equity, rather than as liabilities, on the consolidated balance sheet. Also, net earnings and components of other comprehensive income attributable to the owners of the parent company and to non-controlling interests are now separately disclosed on the consolidated statement of earnings and consolidated statement of comprehensive income.
3. FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards
In October 2009, the AcSB re-confirmed that publicly accountable enterprises in Canada will be required to apply International Financial Reporting Standards ("IFRS"), in full and without modification, beginning January 1, 2011. The Corporation's expected IFRS transition date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported on the Corporation's consolidated opening IFRS balance sheet as at January 1, 2010 and amounts reported by the Corporation for the year ended December 31, 2010.
Fortis is continuing to assess the financial reporting impacts of adopting IFRS. In July 2009, the International Accounting Standards Board ("IASB") issued the Exposure Draft - Rate-Regulated Activities. Based on the Exposure Draft as it currently exists, regulatory assets and liabilities arising from activities subject to cost of service regulation would be recognized under IFRS when certain conditions are met. The ability to record regulatory assets and liabilities, as proposed, should reduce the earnings' volatility at the Corporation's regulated utilities that may otherwise result under IFRS in the absence of an accounting standard for rate-regulated activities, but will result in the requirement to provide enhanced balance sheet presentation and note disclosures. Completion of the IASB's project on Rate-Regulated Activities has been delayed based on comments received in response to the Exposure Draft and a decision by the IASB to conduct further research. Project direction and timeline remain uncertain and may not be known for several months. The continued uncertainty has resulted in the Corporation being unable to reasonably estimate and conclude on the impact on its future consolidated financial position and results of operations with respect to the differences, if any, in accounting for rate-regulated activities under IFRS versus Canadian GAAP.
Fortis anticipates a change in the manner in which it will measure and recognize the value of its income producing properties and a significant increase in disclosure resulting from the adoption of IFRS. The Corporation is identifying and assessing the impact of this change in valuation and additional disclosure requirements, as well as implementing systems changes that will be necessary to compile the required disclosures.
4. USE OF ESTIMATES
The preparation of the Corporation's interim consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are reported in earnings in the period 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, including those related to contingencies, during the three months ended March 31, 2010, except for that described below.
As a result of a recent depreciation study and BCUC-approved NSAs related to TGI and TGVI's 2010 and 2011 revenue requirements, amortization expense at the Terasen Gas companies is expected to increase in 2010, reflecting an increase in the composite depreciation rate to 2.79 per cent for 2010 from 2.63 per cent for 2009. The increase in amortization has been approved for recovery in current customer delivery rates.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. A full description of the nature of the regulatory assets and liabilities is provided in Note 4 to the Corporation's 2009 annual audited consolidated financial statements.
/T/
As at
($ millions) March 31, 2010 December 31, 2009
----------------------------------------------------------------------
----------------------------------------------------------------------
Regulatory Assets
Future income taxes (Note 22) 559 545
Rate stabilization accounts -
Terasen Gas companies 176 82
Rate stabilization accounts -
electric utilities 60 68
Alberta Electric System Operator
("AESO") charges deferral 65 80
Regulatory other post-employment
benefit ("OPEB") plan asset 60 59
Point Lepreau (1) replacement
energy deferral 29 23
Income taxes recoverable on OPEB
plans 18 18
Energy management costs (2) 15 14
Deferred development costs for
capital 7 7
Southern Crossing Pipeline tax
reassessment 7 7
Deferred pension costs 6 6
Lease costs 6 6
Deferred capital asset amortization 3 4
Residential unbundling 2 3
Other regulatory assets 55 44
----------------------------------------------------------------------
Total Regulatory Assets 1,068 966
Less: Current Portion (304) (223)
----------------------------------------------------------------------
Long-Term Regulatory Assets 764 743
----------------------------------------------------------------------
----------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
(2) Relates to costs in providing energy management services to promote
energy efficiency programs to customers at the Terasen Gas
companies, FortisBC, Newfoundland Power and Maritime Electric
As at
($ millions) March 31, 2010 December 31, 2009
----------------------------------------------------------------------
----------------------------------------------------------------------
Regulatory Liabilities
Future asset removal and site
restoration provision 328 326
Future income taxes 34 35
Rate stabilization accounts -
Terasen Gas companies 45 44
Rate stabilization accounts -
electric utilities 22 21
Performance-based rate-setting
incentive liabilities 13 15
Unbilled revenue liability 9 10
Unrecognized net gains on disposal
of utility capital assets (1) 8 -
Southern Crossing Pipeline deferral 7 9
Deferred interest 7 7
Other regulatory liabilities 27 22
----------------------------------------------------------------------
Total Regulatory Liabilities 500 489
Less: Current Portion (45) (53)
----------------------------------------------------------------------
Long-Term Regulatory Liabilities 455 436
----------------------------------------------------------------------
----------------------------------------------------------------------
(1) Relates to amounts reallocated from accumulated amortization at the
Terasen Gas companies, effective January 1, 2010 as approved by the
regulator, for future settlement with customers
/T/
6. INVENTORIES
/T/
As at
($ millions) March 31, 2010 December 31, 2009
--------------------------------------------------------
--------------------------------------------------------
Gas in storage 118 159
Materials and supplies 20 19
--------------------------------------------------------
138 178
--------------------------------------------------------
--------------------------------------------------------
/T/
During the quarter ended March 31, 2010, inventories of $305 million (quarter ended March 31, 2009 - $468 million) were expensed and reported in energy supply costs in the interim consolidated statement of earnings. Inventories expensed to operating expenses during the quarter ended March 31, 2010 were $3 million (quarter ended March 31, 2009 - $3 million), which included $2 million (quarter ended March 31, 2009 - $2 million) for food and beverage costs at Fortis Properties.
7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
/T/
As at
($ millions) March 31, 2010 December 31, 2009
----------------------------------------------------------------------
----------------------------------------------------------------------
Long-term debt and capital lease
obligations 5,304 5,331
Long-term classification of
committed credit facilities (Note
19) 166 208
Deferred debt financing costs (38) (39)
----------------------------------------------------------------------
Total long-term debt and capital
lease obligations 5,432 5,500
Less: Current installments of long-
term debt and capital lease
obligations (336) (224)
----------------------------------------------------------------------
5,096 5,276
----------------------------------------------------------------------
----------------------------------------------------------------------
/T/
8. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value
/T/
As at
Issued and
Outstanding March 31, 2010 December 31, 2009
Number of Number of
Shares Shares
(in Amount (in Amount
thousands)($ millions) thousands)($ millions)
---------------------------------------------------------------
Common shares 172,169 2,520 171,256 2,497
---------------------------------------------------------------
/T/
Common shares issued during the period were as follows:
/T/
Quarter Ended March 31, 2010
Number of
Shares Amount
(in thousands) ($ millions)
------------------------------------------------------------
------------------------------------------------------------
Balance, beginning of period 171,256 2,497
Consumer Share Purchase Plan 14 -
Dividend Reinvestment Plan 568 15
Employee Share Purchase Plan 128 4
Stock Option Plans 203 4
------------------------------------------------------------
Balance, end of period 172,169 2,520
------------------------------------------------------------
------------------------------------------------------------
/T/
Earnings per Common Share
The Corporation calculates earnings per common share on the weighted average number of common shares outstanding. The weighted average number of common shares outstanding was 171.6 million and 169.4 million for the quarters ended March 31, 2010 and March 31, 2009, respectively.
Diluted earnings per common share are calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
Earnings per common share were as follows:
/T/
Quarter Ended March 31
2010 2009
Weighted Earnings Weighted Earnings
Average per Average per
Earnings Shares Common Earnings Shares Common
($ (in ($ (in
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic Earnings
per Common
Share 100 171.6 $0.58 92 169.4 $0.54
Effect of
potential
dilutive
securities:
Stock options - 1.0 - 0.7
Preference
shares (Note
13) 4 11.9 4 13.9
Convertible
debentures 1 1.4 1 1.4
---------------------------------------------------------------------------
Diluted
Earnings per
Common Share 105 185.9 $0.56 97 185.4 $0.52
---------------------------------------------------------------------------
---------------------------------------------------------------------------
/T/
9. PREFERENCE SHARES
In January 2010, the Corporation issued 10 million Cumulative Five-Year Fixed Rate Reset First Preference Shares, Series H ("First Preference Shares, Series H"). The First Preference Shares, Series H were issued at $25.00 per share. The shares are entitled to receive fixed cumulative preferential cash dividends at a rate of $1.0625 per share per annum for each year up to but excluding June 1, 2015. For each five-year period after that date, the holders of First Preference Shares, Series H are entitled to receive reset fixed cumulative preferential cash dividends. The reset annual dividends per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date plus 1.45 per cent.
On each First Preference Shares, Series H Conversion Date, being June 1, 2015 and June 1 every five years thereafter, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series H, at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On each Series H Conversion Date, the holders of First Preference Shares, Series H, have the option to convert any or all of their First Preference Shares, Series H into an equal number of cumulative redeemable floating rate First Preference Shares, Series I.
The holders of First Preference Shares, Series I will be entitled to receive floating rate cumulative preferential cash dividends in the amount per share determined by multiplying the applicable floating quarterly dividend rate by $25.00. The floating quarterly dividend rate will be equal to the sum of the average yield expressed as a percentage per annum on three-month Government of Canada Treasury Bills plus 1.45 per cent.
On each First Preference Shares, Series I Conversion Date, being June 1, 2020 and June 1 every five years thereafter, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series I at a price of $25.00 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On any date after June 1, 2015, that is not a Series I Conversion Date, the Corporation has the option to redeem for cash all or any part of the outstanding First Preference Shares, Series I at a price of $25.50 per share plus all accrued and unpaid dividends up to but excluding the date fixed for redemption. On each Series I Conversion Date, the holders of First Preference Shares, Series I, have the option to convert any or all of their First Preference Shares, Series I into an equal number of First Preference Shares, Series H.
On any Series H Conversion Date, if the Corporation determines that there would be less than 1 million First Preference Shares, Series H outstanding, such remaining First Preference Shares, Series H will automatically be converted into an equal number of First Preference Shares, Series I. On any Series I Conversion Date, if the Corporation determines that there would be less than 1 million First Preference Shares, Series I outstanding, such remaining First Preference Shares, Series I will automatically be converted into an equal number of First Preference Shares, Series H. However, if such automatic conversions would result in less than 1 million Series I First Preference Shares or less than 1 million Series H First Preference Shares outstanding, then no automatic conversion would take place.
As the First Preference Shares, Series H are not redeemable at the option of the shareholder, they are classified as equity.
10. STOCK-BASED COMPENSATION PLANS
In January 2010, 24,426 Deferred Share Units were granted to the Corporation's Board of Directors, representing the equity component of the Directors' annual compensation and, where opted, their annual retainers in lieu of cash. Each Deferred Share Unit represents a unit with an underlying value equivalent to the value of one common share of the Corporation.
In March 2010, 60,000 Performance Share Units were granted to the President and Chief Executive Officer ("CEO") of the Corporation. Each Performance Share Unit ("PSU") represents a unit with an underlying value equivalent to the value of one common share of the Corporation. The maturation period of the March 2010 PSU grant is three years, at which time a cash payment may be made to the President and CEO after evaluation by the Human Resources Committee of the Board of Directors of Fortis of the achievement of payment requirements.
In March 2010, the Corporation granted 892,744 options to purchase common shares under its 2006 Stock Option Plan at the five-day volume weighted average trading price of $27.36 immediately preceding the date of grant. The options vest evenly over a four-year period on each anniversary of the date of grant. The options expire seven years after the date of grant. The fair value of each option granted was $4.41 per option.
The fair value was estimated on the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
/T/
Dividend yield (%) 3.66
Expected volatility (%) 25.1
Risk-free interest rate (%) 2.54
Weighted average expected life (years) 4.5
/T/
As at March 31, 2010, 5.4 million stock options were outstanding and 2.9 million stock options were vested.
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency translation gains and losses, net of hedging activities, gains and losses on cash flow hedging activities and gains and losses on discontinued cash flow hedging activities as described in Note 2 to the Corporation's 2009 annual audited consolidated financial statements.
/T/
Quarter Ended March 31
2010 2009
Opening Ending Opening Ending
balance Net balance balance Net balance
($ millions) January 1 change March 31 January 1 change March 31
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Unrealized
foreign
currency
translation
(losses)
gains, net of
hedging
activities and
tax (78) (8) (86) (46) 9 (37)
Losses on
derivative
instruments
designated as
cash flow
hedges, net of
tax - - - (1) - (1)
Net losses on
derivative
instruments
previously
discontinued
as cash flow
hedges, net of
tax (5) - (5) (5) - (5)
--------------------------------------------------------------------------
Accumulated
Other
Comprehensive
(Loss) Income (83) (8) (91) (52) 9 (43)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
/T/
12. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, other post-employment benefit plans, defined contribution pension plans and group registered retirement savings plans ("RRSPs") for its employees. The cost of providing the defined benefit arrangements was $10 million for the quarter ended March 31, 2010 (quarter ended March 31, 2009 - $6 million). The cost of providing the defined contribution arrangements and group RRSPs for the quarter ended March 31, 2010 was $4 million (quarter ended March 31, 2009 - $4 million).
13. FINANCE CHARGES
/T/
Quarter Ended March 31
($ millions) 2010 2009
-----------------------------------------------------------
-----------------------------------------------------------
Interest - Long-term debt and
capital lease
obligations 88 84
- Short-term
borrowings 2 4
Interest charged to construction (4) (4)
Dividends on preference shares
classified as debt (Note 8) 4 4
-----------------------------------------------------------
90 88
-----------------------------------------------------------
-----------------------------------------------------------
/T/
14. CORPORATE TAXES
Corporate taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory tax rate to earnings before corporate taxes. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
/T/
Quarter Ended March 31
($ millions, except as noted) 2010 2009
-------------------------------------------------------------
-------------------------------------------------------------
Combined Canadian federal and
provincial statutory income tax
rate 32.0% 33.0%
-------------------------------------------------------------
Statutory income tax rate applied
to earnings before corporate taxes 43 41
Preference share dividends 1 1
Difference between Canadian
statutory rate and rates
applicable to foreign subsidiaries (2) (3)
Difference in Canadian provincial
statutory rates applicable to
subsidiaries in different Canadian
jurisdictions (4) (3)
Items capitalized for accounting
but expensed for income tax
purposes (12) (10)
Pension costs - (1)
Other 2 -
-------------------------------------------------------------
Corporate taxes 28 25
-------------------------------------------------------------
Effective tax rate 20.7% 20.3%
-------------------------------------------------------------
-------------------------------------------------------------
/T/
As at March 31, 2010, the Corporation had approximately $96 million (December 31, 2009 - $122 million) in non-capital and capital loss carryforwards, of which $16 million (December 31, 2009 - $16 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2014 and 2029.15. SEGMENTED INFORMATIONInformation by reportable segment is as follows:
/T/
REGULATED
Gas
Quarter Utilities Electric Utilities
ended ---------------------------------------------------------------
March Terasen Electric
31, 2010 Gas Other Total Carib-
($ Companies Fortis Fortis Canadian Electric bean
millions) -Canadian Alberta BC NF Power (1) Canadian (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 529 87 72 178 82 419 76
Energy
supply
costs 305 - 21 131 53 205 45
Operating
expenses 70 35 17 16 11 79 12
Amortization 30 24 10 11 5 50 9
---------------------------------------------------------------------------
Operating
income 124 28 24 20 13 85 10
Finance
charges 27 14 8 9 6 37 5
Corporate
taxes
(recoveries) 24 - 2 4 2 8 -
---------------------------------------------------------------------------
Net earnings
(loss) 73 14 14 7 5 40 5
Non-
controlling
interest - - - - - - (1)
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 73 14 14 7 5 40 4
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 136
Identifiable
assets 4,130 1,922 1,157 1,211 623 4,913 784
---------------------------------------------------------------------------
Total assets 5,038 2,149 1,378 1,211 686 5,424 920
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross
capital
expenditures
(4) 50 64 26 17 8 115 17
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter
ended
March 31,
2009
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 669 79 72 169 71 391 83
Energy
supply
costs 468 - 22 127 47 196 46
Operating
expenses 67 34 17 14 8 73 14
Amortization 25 22 10 11 4 47 11
---------------------------------------------------------------------------
Operating
income 109 23 23 17 12 75 12
Finance
charges 32 11 7 8 5 31 4
Corporate
taxes
(recoveries) 19 - 2 3 2 7 -
---------------------------------------------------------------------------
Net earnings
(loss) 58 12 14 6 5 37 8
Non-
controlling
interest - - - - - - (2)
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 58 12 14 6 5 37 6
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 168
Identifiable
assets 4,057 1,661 1,079 1,166 519 4,425 888
---------------------------------------------------------------------------
Total assets 4,965 1,888 1,300 1,166 582 4,936 1,056
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross
capital
expenditures
(4) 50 90 22 13 12 137 20
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
Quarter
ended
March 31,
2010 Fortis Inter-
($ Generation Fortis Corporate segment
millions) (3) Properties and Other eliminations Consolidated
--------------------------------------------------------------------
--------------------------------------------------------------------
Revenue 5 49 7 (9) 1,076
Energy
supply
costs - - - (3) 552
Operating
expenses 2 36 4 (1) 202
Amortization 1 4 3 - 97
--------------------------------------------------------------------
Operating
income 2 9 - (5) 225
Finance
charges - 6 20 (5) 90
Corporate
taxes
(recoveries) - 1 (5) - 28
--------------------------------------------------------------------
Net earnings
(loss) 2 2 (15) - 107
Non-
controlling
interest - - - - (1)
Preference
share
dividends - - (6) - (6)
--------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 2 2 (21) - 100
--------------------------------------------------------------------
--------------------------------------------------------------------
Goodwill - - - - 1,555
Identifiable
assets 183 607 107 (19) 10,705
--------------------------------------------------------------------
Total assets 183 607 107 (19) 12,260
--------------------------------------------------------------------
--------------------------------------------------------------------
Gross
capital
expenditures
(4) 1 5 - - 188
--------------------------------------------------------------------
--------------------------------------------------------------------
Quarter
ended
March 31,
2009
--------------------------------------------------------------------
--------------------------------------------------------------------
Revenue 16 47 7 (11) 1,202
Energy
supply
costs 1 - - (4) 707
Operating
expenses 4 34 3 (2) 193
Amortization 2 4 2 - 91
--------------------------------------------------------------------
Operating
income 9 9 2 (5) 211
Finance
charges 1 6 19 (5) 88
Corporate
taxes
(recoveries) 2 1 (4) 25
--------------------------------------------------------------------
Net earnings
(loss) 6 2 (13) - 98
Non-
controlling
interest - - - - (2)
Preference
share
dividends - - (4) - (4)
--------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 6 2 (17) - 92
--------------------------------------------------------------------
--------------------------------------------------------------------
Goodwill - - - - 1,587
Identifiable
assets 208 562 131 (10) 10,261
--------------------------------------------------------------------
Total assets 208 562 131 (10) 11,848
--------------------------------------------------------------------
--------------------------------------------------------------------
Gross
capital
expenditures
(4) 7 5 - - 219
--------------------------------------------------------------------
--------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario includes
Algoma Power from October 8, 2009, the date of acquisition by
FortisOntario.
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(3) Results reflect the expiry, on April 30, 2009, at the end of
a 100-year term, of the 75 MW of water-right entitlement associated
with the Rankine hydroelectric generating facility at Niagara Falls.
Relates to utility capital assets, including amounts for AESO
transmision
(4) capital projects, and to income producing properties and intangible
assets, as reflected in the consolidated statement of cash flows
/T/
Inter-segment 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 inter-segment transactions primarily related to the sale of energy from Fortis Generation to Belize Electricity, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-segment borrowings. The significant inter-segment transactions for the three months ended March 31, 2010 and 2009 were as follows.
/T/
Significant Inter-Segment
Transactions Quarter Ended March 31
($ millions) 2010 2009
-------------------------------------------------------------
-------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities -
Caribbean 3 4
Sales from Newfoundland Power to
Fortis Properties 1 1
Inter-segment finance charges on
borrowings from:
Corporate to Regulated Electric
Utilities - Caribbean 2 2
Corporate to Fortis Properties 2 2
-------------------------------------------------------------
-------------------------------------------------------------
/T/
16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
/T/
Quarter Ended March 31
($ millions) 2010 2009
-----------------------------------------------------------
-----------------------------------------------------------
Interest paid 90 85
Income taxes paid 24 65
-----------------------------------------------------------
-----------------------------------------------------------
/T/
17. CAPITAL MANAGEMENT
The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital in order to allow the utilities to fund the 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 with proceeds from common and preference share issuances. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent 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 the utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
/T/
As at
March 31, 2010 December 31, 2009
($ millions) (%)($ millions) (%)
---------------------------------------------------------------------
---------------------------------------------------------------------
Total debt and capital
lease obligations (net
of cash) (1) 5,573 57.5 5,830 60.2
Preference shares (2) 912 9.4 667 6.9
Common shareholders'
equity 3,212 33.1 3,193 32.9
---------------------------------------------------------------------
Total (3) 9,697 100.0 9,690 100.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term
liabilities and equity
(3) Excludes amounts related to non-controlling interests
/T/
Certain of the Corporation's long-term debt obligations have covenants restricting the issuance of additional debt such that consolidated debt cannot exceed 70 per cent of the Corporation's consolidated capital structure, as defined by the long-term debt agreements. As at March 31, 2010, the Corporation and its subsidiaries, except for certain debt at Belize Electricity and the Exploits Partnership, as described below, were in compliance with their debt covenants.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application in June 2008, Belize Electricity does not meet certain debt covenant financial ratios related to loans with the International Bank for Reconstruction and Development and the Caribbean Development Bank totalling $6 million (BZ$11 million) as at March 31, 2010.
As the hydroelectric assets and water rights of the Exploits Partnership had been provided as security for the Exploits Partnership term loan, the expropriation of such assets and rights by the Government of Newfoundland and Labrador constituted an event of default under the loan. The term loan is without recourse to Fortis and was approximately $59 million as at March 31, 2010 (December 31, 2009 - $59 million). The lenders of the term loan have not demanded accelerated repayment. The scheduled repayments under the term loan are being made by Nalcor, a Crown corporation, acting as agent for the Government of Newfoundland and Labrador with respect to the expropriation matters.
The Corporation's credit ratings and consolidated credit facilities are discussed further under "Liquidity Risk" in Note 19.
18. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the three months ended March 31, 2010 in the designation of the Corporation's financial instruments from that disclosed in the Corporation's 2009 annual audited consolidated financial statements. The carrying values of financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or the nature of these instruments. The carrying and fair values of the Corporation's consolidated long-term debt and preference shares were as follows:
/T/
As at
March 31, 2010 December 31, 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Long-term debt, including
current portion (1) (2) 5,433 5,921 5,502 5,906
Preference shares, classified
as debt (1) (3) 320 357 320 348
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1) Carrying value is measured at amortized cost using the effective
interest rate method.
(2) Carrying value as at March 31, 2010 excludes unamortized deferred
financing costs of $38 million (December 31, 2009 - $39 million) and
capital lease obligations of $37 million (December 31, 2009 - $37
million).
(3) Preference shares classified as equity are excluded from the
requirements of the CICA Handbook Section 3855, Financial Instrument,
Recognition and Measurement; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was
$595 million as at March 31, 2010 (December 31, 2009 - carrying value
$347 million; fair value $356 million).
/T/
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes. The following table summarizes the valuation of the Corporation's consolidated derivative financial instruments.
/T/
As at
March 31, 2010 December, 31, 2009
Carrying Fair Carrying Estimated
Term to Number Value Value Value Fair Value
Maturity of ($ ($ ($ ($
Liability years) Contracts millions) millions) millions) millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest rate less
swap (1) (2) than 1 1 - - - -
Foreign
exchange
forward
contracts
(3)(4) 1 to 2 2 - - - -
Natural gas
derivatives:
(3)(5)
Swaps and
options Up to 5 186 (194) (194) (119) (119)
Gas purchase
contract
premiums Up to 2 24 (3) (3) (3) (3)
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(1) Interest rate swap contract matures in October 2010. The contract has
the effect of fixing the rate of interest on the non-revolving credit
facilities of Fortis Properties at 5.32 per cent.
(2) The fair value measurements are Level 1, based on the three levels that
distinguish the level of pricing observability utilized in measuring
fair value.
(3) The fair value measurements are Level 2, based on the three levels that
distinguish the level of pricing observability utilized in measuring
fair value.
(4) The fair values of the foreign exchange forward contracts were recorded
in accounts payable as at March 31, 2010 and accounts receivable as at
December 31, 2009.
(5) The fair values of the natural gas derivatives were recorded in
accounts payable as at March 31, 2010 and as at December 31, 2009.
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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.
19. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
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Credit risk Risk that a third party 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.
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Credit Risk
For cash and cash equivalents, trade and other accounts receivable, and other receivables due from customers, the Corporation's credit risk is 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 and 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 and, as at March 31, 2010, its gross credit risk exposure was approximately $93 million, representing the projected value of retailer billings over a 60-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, 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 Terasen Gas companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments. The Terasen Gas companies are also exposed to credit risk on physical off-system sales. To help mitigate credit risk, the Terasen Gas companies deal with high credit-quality institutions in accordance with established credit-approval practices. The counterparties with which the Terasen Gas companies have significant transactions are A-rated entities or better. The Terasen Gas companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist.
The aging analysis of the Corporation's consolidated trade and other accounts receivable, net of an allowance for doubtful accounts of $17 million as at March 31, 2010 (December 31, 2009 - $17 million; March 31, 2009 - $19 million), excluding derivative financial instruments recorded in accounts receivable, was as follows:
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As at
($ millions) March 31, 2010 December 31, 2009 March 31, 2009
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Not past due 518 527 608
Past due 0-30 days 63 52 91
Past due 31-60 days 14 8 21
Past due 61 days and over 9 8 7
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604 595 727
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As at March 31, 2010, other receivables due from customers of $7 million (included in other assets) will be received over the next five years and, thereafter, with $2 million expected to be received in year 1, $3 million over years 2 and 3, $1 million over years 4 and 5 and $1 million due after 5 years.
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 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 credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at March 31, 2010, average annual consolidated long-term debt maturities and repayments over the next five years are expected to be approximately $280 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, 2010, the Corporation and subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which $1.6 billion was unused. The credit facilities are syndicated almost entirely with the seven largest Canadian banks with no one bank holding more than 25 per cent of these facilities.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
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As at
Corporate Regulated Fortis March 31, December 31,
($ millions) and Other Utilities Properties 2010 2009
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Total credit
facilities 645 1,493 13 2,151 2,153
Credit facilities
utilized:
Short-term
borrowings - (233) - (233) (415)
Long-term debt
(including current
portion) (Note 7) (53) (113) - (166) (208)
Letters of credit
outstanding (1) (115) (1) (117) (100)
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Credit facilities
unused 591 1,032 12 1,635 1,430
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As at March 31, 2010 and December 31, 2009, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods.
In February 2010, Maritime Electric renewed its $50 million unsecured committed revolving credit facility, which matures annually in March.
In March 2010, FortisBC negotiated an extension of its $150 million unsecured committed revolving credit facility, of which $100 million now matures May 2013 and the remaining $50 million now matures May 2011. The amended credit facility agreement is expected to be finalized during the second quarter of 2010.
The following is an analysis of the contractual maturities of the Corporation's consolidated financial liabilities as at March 31, 2010.
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Financial Liabilities Due Due in Due in Due
within 1 years 2 years 4 after 5
($ millions) year and 3 and 5 years Total
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Short-term borrowings 233 - - - 233
Trade and other
accounts payable 692 - - - 692
Natural gas
derivatives (1) 127 57 9 - 193
Foreign exchange
forward contracts (2) 15 7 - - 22
Dividends payable 53 - - - 53
Customer deposits (3) 2 2 1 2 7
Long-term debt,
including current
portion (4) 333 297 771 4,032 5,433
Interest obligations
on long-term debt 331 643 616 4,629 6,219
Preference shares,
classified as debt - - 123 197 320
Dividend obligations
on preference shares
classified as interest
expense 17 33 22 14 86
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1,803 1,039 1,542 8,874 13,258
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(1) Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at March 31, 2010 at $197
million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts payable at fair value as at March 31, 2010 at $0.2
million.
(3) Customer deposits were recorded in deferred credits as at March 31,
2010.
(4) Excludes deferred financing costs of $38 million and capital lease
obligations of $37 million
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Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, self-sustaining foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has effectively decreased the above 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 or a currency pegged to the US dollar. Belize Electricity's reporting currency is the Belizean dollar while the reporting currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and BECOL is the US dollar. The Belizean dollar is pegged to the US dollar at BZ$2.00=US$1.00.
As at March 31, 2010, the Corporation's corporately held US$390 million (December 31, 2009 - US$390 million) long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. As at March 31, 2010, the Corporation had approximately US$179 million (December 31, 2009 - US$174 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately held US dollar borrowings that are designated as hedges are recorded in other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the foreign net investments, which are also recorded in other comprehensive income.
TGI and TGVI's US dollar payments under contracts for the implementation of a customer information system and the construction of a liquefied natural gas storage facility, respectively, expose the utilities to fluctuations in the US dollar-to-Canadian dollar exchange rate. TGI and TGVI have entered into foreign exchange forward contracts to hedge this exposure and any increase or decrease in the fair value of the foreign exchange forward contracts is deferred for recovery from, or refund to, customers in future rates, subject to regulatory approval.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk associated with short-term borrowings and floating-rate debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.
As at March 31, 2010, Fortis Properties was party to one interest rate swap agreement that effectively fixed the interest rate on variable-rate borrowings.
The Terasen Gas companies and FortisBC have regulatory approval to defer any increase or decrease in interest expense resulting from fluctuations in interest rates associated with variable-rate debt for recovery from, or refund to, customers in future rates.
Commodity Price Risk
The Terasen Gas companies are exposed to commodity price risk associated with changes in the market price of natural gas. This risk is minimized by entering into natural gas derivatives that effectively fix the price of natural gas purchases. The price risk-management strategy of the Terasen Gas companies aims to improve the likelihood that natural gas prices remain competitive with electricity rates, temper gas price volatility on customer rates and reduce the risk of regional price discrepancies. The natural gas derivatives are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, subject to regulatory approval, for recovery from, or refund to, customers in future rates.
20. CONTINGENT LIABILITIES AND COMMITMENTS
Contingent Liabilities
The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with ordinary course 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. There were no material changes in the Corporation's contingencies from those disclosed in the Corporation's 2009 annual audited consolidated financial statements.
Commitments
There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2009 annual audited consolidated financial statements, except for that described below.
During the first quarter of 2010, FortisBC entered into a contract with Powerex Corp., a wholly owned subsidiary of BC Hydro, for fixed-price winter capacity purchases through to February 2016 in an aggregate amount of approximately US$16 million. If FortisBC brings any new resources, such as capital or contractual projects, on-line prior to the expiry of this agreement, FortisBC may terminate this contract any time after July 1, 2013 with a minimum of three-months written notice to Powerex Corp.
21. SUBSEQUENT EVENT
In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital Securities with proceeds from borrowings under the Corporation's committed credit facility.
22. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period classifications, the most significant of which was the reclassification of $15 million from long-term regulatory assets to utility capital assets ($9 million) and long-term future tax liabilities ($6 million) at the Terasen Gas companies.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada. With total assets exceeding $12 billion and fiscal 2009 revenue totalling $3.6 billion, the Corporation serves approximately 2,100,000 gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and three Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upper New York State. It also owns and operates hotels and commercial office and retail space primarily in Atlantic Canada. Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the symbol FTS.
Share Transfer Agent and Registrar:
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Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
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Additional information, including the Fortis 2009 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.
Fortis Inc.
Barry V. Perry
Vice President Finance and Chief Financial Officer
709-737-2800