Fortis Earns $36 Million in Third Quarter of 2009
NOV 5, 2009 - 07:00 ET
FOR: FORTIS INC.
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ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - Nov. 5, 2009) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) recorded third quarter net earnings applicable to common shares of $36 million, or $0.21 per common share, compared to earnings of $49 million, or $0.31 per common share, for the third quarter of 2008. Earnings were $1 million lower quarter over quarter, excluding one-time tax reductions of $12 million at Terasen and FortisAlberta in the third quarter last year. Year-to-date earnings applicable to common shares were $181 million, or $1.06 per common share, compared to earnings of $169 million, or $1.08 per common share, for the same period last year.
The Terasen Gas companies incurred a loss of $3 million for the third quarter of 2009 compared to earnings of $1 million for the same period last year. Excluding a $5.5 million tax reduction in the third quarter of 2008 associated with the settlement of historical corporate tax matters, results were $1.5 million higher quarter over quarter. The increase was mainly due to lower effective corporate income taxes.
Canadian Regulated Electric Utilities contributed $36 million to earnings for the third quarter compared to $38 million for the same period last year. Excluding a $4.5 million recovery of future income taxes at FortisAlberta during the third quarter of 2008, earnings were $2.5 million higher quarter over quarter. Improved performance at FortisAlberta, due to growth in electrical infrastructure investment and higher net transmission revenue, was partially offset by lower earnings at Newfoundland Power largely associated with higher operating expenses and amortization costs.
During the second quarter of 2009, Terasen Gas, Terasen Gas (Vancouver Island) and FortisAlberta filed applications with their respective regulators to set 2010 and 2011 customer rates and Newfoundland Power filed an application with its regulator to set 2010 customer rates. Each of these utilities has requested, or is currently engaged in, a cost of capital review, the outcome of which could result in a change in the allowed rate of return on common shareholder's equity.
In October 2009, FortisOntario acquired Great Lakes Power Distribution Inc., subsequently renamed Algoma Power Inc. ("Algoma Power"), for an aggregate purchase price of $75 million, including cash acquired, subject to adjustment. Algoma Power is a regulated electric distribution utility serving approximately 12,000 customers in the district of Algoma in northern Ontario.
Caribbean Regulated Electric Utilities contributed $7 million to earnings, comparable to the third quarter of 2008. Results for the quarter were impacted by slower electricity sales growth as a result of the global economic downturn.
Non-Regulated Fortis Generation contributed $4 million to earnings compared to $9 million for the third quarter of 2008. As expected, results for the quarter were unfavourably impacted by the loss of earnings subsequent to the expiration, on April 30, 2009, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario. Lower average wholesale market energy prices in Upper New York State and lower production in Belize also contributed to the decrease in earnings.
Fortis Properties contributed $9 million to earnings, comparable to the third quarter of 2008. Contributions from recently acquired hotels and the Real Estate Division were offset by the impact of generally lower occupancies at the remainder of the Company's hotels.
Corporate and other expenses were $17 million compared to $15 million for the same quarter in 2008. Excluding a $1 million favourable tax adjustment in the third quarter of 2009 and a $2 million tax reduction associated with the settlement of historical corporate tax matters at Terasen in the third quarter of 2008, corporate and other expenses were $1 million higher quarter over quarter. The increase was driven by higher finance charges associated with the $200 million debentures issued in July 2009. In December 2008, Fortis completed a $300 million common share issue, the net proceeds of which were primarily used to repay short-term debt incurred to repay maturing long-term debt.
Cash flow from operating activities was $567 million year to date compared to $452 million for the same period last year. The increase in cash from operating activities was largely attributable to FortisAlberta and the Terasen Gas companies.
Consolidated capital expenditures, before customer contributions, were $763 million year to date. Some of the larger projects in progress include construction of the liquefied natural gas storage facility at Terasen Gas (Vancouver Island), the installation of automated customer meters at FortisAlberta, the Okanagan Transmission Reinforcement Project at FortisBC and BECOL's 19-megawatt Vaca hydroelectric generating facility in Belize.
Year to date, Fortis and its utilities have raised more than $700 million of long-term debt, including 30-year $200 million 6.51% unsecured debentures at Fortis, 30-year $105 million 6.10% unsecured debentures at FortisBC, 15-year US$40 million 7.50% unsecured notes at Caribbean Utilities, 30-year $65 million 6.606% first mortgage bonds at Newfoundland Power, 30-year $100 million 6.55% unsecured debentures at Terasen Gas, 30-year $100 million 7.06% unsecured debentures at FortisAlberta and an additional 30-year $125 million 5.37% unsecured debentures at FortisAlberta issued subsequent to the quarter end.
As at September 30, 2009, Fortis had consolidated credit facilities of approximately $2.2 billion, $1.6 billion of which was unused. Over the next five years, average consolidated annual long-term debt maturities and repayments are expected to be approximately $157 million.
In September 2009, Standard & Poor's confirmed its credit rating for Fortis at A- (stable outlook), reflecting the diversity of the Corporation's regulated utility operations, stability and predictability of the utilities' cash flows and the Corporation's focused, well-executed growth strategy.
"Our equity issue last December strengthened the consolidated balance sheet of Fortis and improved liquidity," explains Stan Marshall, President and Chief Executive Officer, Fortis Inc. "Notwithstanding ongoing global economic challenges, Fortis anticipates that its capital program will surpass $1 billion this year. Our five-year $5 billion capital program, which is being driven by investment in infrastructure at our Regulated Utilities in western Canada, should allow rate base to grow, on average, approximately 6 to 7 per cent annually. This capital investment should drive growth in earnings and dividends," concludes Marshall.
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2009
Dated November 5, 2009
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 and nine months ended September 30, 2009 and the Management Discussion and Analysis ("MD&A") and audited consolidated financial statements for the year ended December 31, 2008 included in the Corporation's 2008 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 management. The forward-looking information in the MD&A includes, but is not limited to, statements regarding: the expected timing of regulatory decisions; consolidated forecasted gross capital expenditures for 2009 and in total over the five-year period from 2009 to 2013;
the nature, timing and amount of certain capital projects; the expected impacts on Fortis of the downturn in the global economy; the electricity sales growth rate expected at the Corporation's regulated utilities in the Caribbean in 2009; the expectation of no significant decrease in annual consolidated operating cash flows in 2009; the expectation that the subsidiaries will be able to source the cash required to fund their 2009 capital expenditure programs; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to long-term capital in the near to medium terms; expected long-term debt maturities and repayments on average annually over the next five years; no material increase in interest expense and/or fees associated with renewed and extended credit facilities is expected in 2009; no material adverse credit rating actions are expected in the near term; the expectation that counterparties to the Terasen Gas companies' gas derivative contracts will continue to meet their obligations; and the expectation of no material increase in defined benefit pension expense in 2009. 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 2009; 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; 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; an ultimate resolution of the expropriation of the assets of the Exploits River Hydro Partnership that differs from what is currently expected by management; 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; an unexpected outcome of any legal proceedings currently against the Corporation; loss of licences and permits; loss of service area; market energy sales prices; changes in current assumptions and expectations associated with the transition to International Financial Reporting Standards; changes in tax legislation; relations 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 and nine months ended September 30, 2009 and for the year ended December 31, 2008.
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 more than 2,000,000 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 real estate in Canada. Year-to-date September 30, 2009, the Corporation's electric utilities met a combined peak electricity demand of 5,684 megawatts ("MW") and its gas utility met a peak day demand of 1,234 terajoules ("TJ"). For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2009.
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 reasonable rates, and conduct business in an environmentally responsible manner. The Corporation's core utility business 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 third quarter and year-to-date periods ended September 30, 2009 and September 30, 2008, are provided in the following table.
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Financial Highlights (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
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($ millions, except
earnings per
common share and
common shares
outstanding) 2009 2008 Variance 2009 2008 Variance
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Revenue 664 727 (63) 2,619 2,721 (102)
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Cash flow from
operating
activities 63 27 36 567 452 115
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Net earnings
applicable to
common shares 36 49 (13) 181 169 12
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Basic earnings per
common share ($) 0.21 0.31 (0.10) 1.06 1.08 (0.02)
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Diluted earnings
per common
share ($) 0.21 0.31 (0.10) 1.05 1.06 (0.01)
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Weighted average
number of common
shares outstanding
(millions) 170.4 157.2 13.2 170.0 156.9 13.1
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Segmented Net Earnings
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Quarter Year-to-date
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2009 2008 Variance 2009 2008 Variance
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Regulated Gas
Utilities -
Canadian
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Terasen Gas
Companies (1) (3) 1 (4) 69 71 (2)
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Regulated Electric
Utilities -
Canadian
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FortisAlberta 16 17 (1) 45 35 10
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FortisBC (2) 8 8 - 29 27 2
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Newfoundland
Power 7 8 (1) 24 24 -
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Other Canadian (3) 5 5 - 14 11 3
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36 38 (2) 112 97 15
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Regulated Electric
Utilities -
Caribbean (4) 7 7 - 20 9 11
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Non-Regulated -
Fortis
Generation (5) 4 9 (5) 13 22 (9)
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Non-Regulated -
Fortis
Properties (6) 9 9 - 19 19 -
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Corporate and
Other (7) (17) (15) (2) (52) (49) (3)
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Net Earnings
Applicable to
Common Shares 36 49 (13) 181 169 12
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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 and Cornwall Electric.
(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, including an additional 2.7 per cent interest
acquired in July 2009; and wholly owned Fortis Turks and Caicos.
Previously, Caribbean Utilities had an April 30th fiscal year end
whereby, up to and including the third quarter of 2008, its financial
statements were consolidated in the financial statements of Fortis on a
two-month lag basis. In 2008, Caribbean Utilities changed its fiscal
year end to December 31st. The change in Caribbean Utilities' fiscal
year end eliminates the previous two-month lag in consolidating its
financial results.
(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 120 MW, mainly
hydroelectric. Prior to May 1, 2009, the Corporation's financial
results reflected earnings' contribution associated with the
Corporation's 75-MW water-right entitlement on the Niagara River in
Ontario under the Niagara Exchange Agreement related to the Rankine
hydroelectric generating facility. The Niagara Exchange Agreement
expired on April 30, 2009, in accordance with its terms.
Additionally, prior to February 13, 2009, the financial results of the
hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. As of February 13,
2009, the financial results of the generation operations in central
Newfoundland have been recorded in the financial statements of Fortis
on an equity basis, due to the Corporation no longer having control
over the generation operations as a result of the expropriation of the
related assets by the Government of Newfoundland and Labrador. The
change in the method of accounting did not have a material impact on
segmented or consolidated earnings. For a further discussion of this
matter, refer to the "Critical Accounting Estimates - Contingencies"
section of this MD&A.
(6) Fortis Properties owns 21 hotels with more than 4,000 rooms in eight
Canadian provinces and approximately 2.8 million square feet of
commercial real estate 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.
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SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
Terasen Gas Companies
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Terasen Gas Companies
Financial Highlights (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
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2009 2008 Variance 2009 2008 Variance
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Gas Volumes (TJ) 22,428 30,798 (8,370) 136,849 154,306 (17,457)
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($ millions)
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Revenue 208 271 (63) 1,166 1,296 (130)
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Energy Supply Costs 98 157 (59) 722 850 (128)
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Operating Expenses 60 59 1 189 182 7
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Amortization 25 24 1 76 73 3
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Finance Charges 30 33 (3) 91 96 (5)
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Corporate Tax
(Recovery) Expense (2) (3) 1 19 24 (5)
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Earnings (3) 1 (4) 69 71 (2)
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Gas Volumes: Gas volumes at the Terasen Gas companies decreased 8,370 TJ, or 27.2 per cent, quarter over quarter and decreased 17,457 TJ, or 11.3 per cent, year to date compared to the same period last year. The following is a breakdown of gas volumes by major customer category.
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Terasen Gas Companies
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
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(YJ) 2009 2008 Variance 2009 2008 Variance
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Core - residential
and commercial 10,749 13,544 (2,795) 81,237 87,860 (6,623)
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Industrial 346 1,061 (715) 3,963 4,740 (777)
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Total sales
volumes 11,095 14,605 (3,510) 85,200 92,600 (7,400)
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Transportation
volumes 9,620 12,019 (2,399) 42,354 47,642 (5,288)
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Throughput under
fixed revenue
contracts 1,713 4,174 (2,461) 9,295 14,064 (4,769)
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Total volumes 22,428 30,798 (8,370) 136,849 154,306 (17,457)
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The decrease in gas volumes to core customers quarter over quarter was mainly due to lower average consumption as a result of warmer-than-normal weather experienced during the third quarter of 2009. The decrease in gas volumes to core customers year to date compared to the same period last year was mainly due to lower average consumption as a result of warmer-than-normal weather experienced during the second and third quarters of 2009, partially offset by higher average consumption during first quarter of 2009 as a result of cooler-than-normal weather experienced during that quarter. The decrease in gas volumes for the quarter and year to date, for all other customers was mainly due to the negative impact of the general economic slowdown.
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 of natural gas only.
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 distribution rates do not materially affect earnings.
During the third quarter of 2009, combined net customer losses at Terasen Gas Inc. ("TGI") and Terasen Gas (Vancouver Island) Inc. ("TGVI") totalled approximately 300, bringing the total customer count at the Terasen Gas companies to approximately 932,200 as at September 30, 2009. Year-to-date 2009, net customer additions were approximately 800 compared to net customer additions of approximately 5,600 for the same period in 2008. Continued weakening housing and construction markets, due to slowing economic growth, and growth in multi-family housing, where natural gas use is less prevalent compared to single-family housing, has resulted in lower customer growth year to date compared to the same period in 2008.
Revenue: Revenue was $63 million lower quarter over quarter and $130 million lower year to date compared to the same period last year. The decreases were largely due to lower commodity costs charged to customers and lower consumption, partially offset by higher basic customer delivery rates compared to the same periods in 2008.
Effective January 1, 2009, basic customer delivery rates at TGI increased approximately 6 per cent while basic customer delivery rates at TGVI increased up to 5 per cent based on customer rate class. The basic customer delivery rates for 2009, however, reflect the impact of a decrease in the allowed rate of return on common shareholder's equity ("ROE") to 8.47 per cent from 8.62 per cent for TGI and to 9.17 per cent from 9.32 per cent for TGVI.
Earnings: Excluding a $5.5 million tax reduction in the third quarter of 2008 associated with the settlement of historical corporate tax matters, earnings were approximately $1.5 million higher quarter over quarter and approximately $3.5 million higher year to date compared to the same period last year. The increases were mainly due to a lower effective corporate income tax rate and higher basic customer delivery rates, partially offset by increased amortization costs associated with continued investment in capital assets and higher operating expenses, driven by increased labour and employee-benefit costs and property taxes. The decrease in the effective corporate income tax rate was primarily due to higher deductions taken for tax purposes compared to accounting purposes.
As reflected in 2009 customer rates, finance charges were lower quarter over quarter and lower year to date compared to the same period last year due to decreased borrowing rates and incrementally lower borrowings under credit facilities.
In February 2009, TGI issued 30-year $100 million 6.55% unsecured debentures. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to the Terasen Gas companies, refer to the "Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
FortisAlberta
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Fortis Alberta
Financial Highlights (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
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2009 2008 Variance 2009 2008 Variance
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Energy Deliveries
(GWh) 3,819 3,748 71 11,736 11,654 82
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($ millions)
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Revenue 85 74 11 245 222 23
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Operating Expenses 33 31 2 98 96 2
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Amortization 25 22 3 70 63 7
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Finance Charges 12 10 2 36 30 6
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Corporate Tax
Recovery (1) (6) 5 (4) (2) (2)
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Earnings 16 17 (1) 45 35 10
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Energy Deliveries: Energy deliveries at FortisAlberta increased 71 gigawatt hours ("GWh"), or 1.9 per cent, quarter over quarter, mainly due to an increase in residential, commercial, farm and irrigation customers. Energy deliveries increased 82 GWh, or 0.7 per cent, year to date compared to the same period last year, mainly due to an increase in residential, commercial, farm and irrigation customers and the impact of cooler-than-normal weather during the first quarter of 2009, partially offset by a decrease in the number of industrial customers. Year-to-date 2009, the number of customers at FortisAlberta increased approximately 15,200 to 476,200.
As a significant portion of the Company's distribution revenue is derived from fixed, or largely fixed, billing determinants, changes in quantities of energy delivered do not directly correlate with changes in revenues.
Revenue: Revenue was $11 million higher quarter over quarter and $23 million higher year to date compared to the same period last year, mainly due to an 8.6 per cent increase in customer distribution rates, effective January 1, 2009, the impact of load and customer growth, and higher net transmission and miscellaneous revenues. Customer distribution rates for 2009 reflect the impact of ongoing investment in electrical infrastructure and collection from customers in 2009 of the increase in the allowed ROE for 2008 that was accrued in 2008. Rates for 2009 reflect an interim allowed ROE of 8.51 per cent compared to an allowed ROE of 8.75 per cent for 2008. Net transmission revenue increased approximately $1 million quarter over quarter and $2 million year to date compared to the same period last. FortisAlberta assumes volume risk on actual transmission costs relative to those charged to customers, which are based on forecast volumes and prices. When transmission volumes are higher (lower) than forecast, the net impact is favourable (unfavourable) to FortisAlberta's revenue.
Earnings: Earnings were $1 million lower quarter over quarter, driven by lower corporate income tax recoveries. Excluding a $4.5 million recovery of future income taxes during the third quarter of 2008 that was previously expensed during the first half of 2008, earnings increased $3.5 million. The impact of the increase in customer distribution rates, overall load and customer growth and higher net transmission revenue was partially offset by: (i) higher operating expenses due to higher labour and employee-benefit costs associated with increased salaries and number of employees and increased contracted manpower costs, partially offset by lower general operating costs; (ii) increased amortization costs associated with continued investment in capital assets; and (iii) 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 credit facility borrowings.
The decrease in corporate income tax recoveries was mainly due to lower future income tax recoveries, driven by a change in tax strategy during the third quarter of 2008 related to the Company's regulator-approved Alberta Electric System Operator ("AESO") charges deferral account, combined with lower current income tax recoveries. Prior to the third quarter of 2008, FortisAlberta was not deducting for income tax purposes transmission tariff payments made to the AESO to create tax loss carryforwards and, therefore, was not recording the associated future income tax recoveries. During the third quarter of 2008, a $4.5 million recovery of future income taxes was recorded, as described above, as a result of the change in tax strategy. However, the collection in 2009 of the balance of the 2007 AESO charges deferral account that was not sold to a Canadian chartered bank in 2007 results in a future income tax recovery in 2009.
Earnings were $10 million higher year to date compared to the same period last year. The impact of the increase in customer distribution rates, overall load and customer growth, increased net transmission revenue and higher corporate tax recoveries was partially offset by higher operating expenses, amortization costs and finance charges for the reasons described above for the quarter. Corporate tax recoveries were higher due to higher future income tax recoveries associated with an increase in regulatory deferrals, other than the AESO charges deferrals, and future income tax recovery associated with the collection in 2009 of the 2007 AESO charges deferral account, as described above for the quarter.
In February 2009, FortisAlberta issued 30-year $100 million 7.06% unsecured debentures. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
In October 2009, FortiaAlberta issued 30-year $125 million 5.37% unsecured debentures, the net proceeds of which will be used to repay committed credit facility borrowings that were incurred primarily to finance capital expenditures, and for general corporate purposes.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisAlberta, refer to the "Regulatory Highlights" section of this MD&A.
FortisBC
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Fortis BC
Financial Highlights (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
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2009 2008 Variance 2009 2008 Variance
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Electricity Sales
(GWh) 720 697 23 2,298 2,245 53
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($ millions)
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Revenue 57 52 5 184 171 13
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Energy Supply Costs 15 12 3 50 45 5
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Operating Expenses 17 16 1 51 49 2
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Amortization 9 8 1 28 25 3
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Finance Charges 8 7 1 23 21 2
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Corporate Taxes - 1 (1) 3 4 (1)
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Earnings 8 8 - 29 27 2
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Electricity Sales: Electricity sales at FortisBC increased 23 GWh, or 3.3 per cent, quarter over quarter and increased 53 GWh, or 2.4 per cent, year to date compared to the same period last year, primarily due to growth in residential and general service customers, partially offset by a decrease in the number of industrial customers.
Revenue: Revenue was $5 million higher quarter over quarter and $13 million higher year to date compared to the same period last year. The increases were driven by: (i) a 4.6 per cent increase in customer electricity rates, effective January 1, 2009; (ii) a 2.2 per cent increase in customer electricity rates, effective September 1, 2009, as a result of the flow through to customers of increased power purchase costs from BC Hydro; and (iii) electricity sales growth, partially offset by an increase in performance-based rate setting ("PBR") incentive adjustments owing to customers. Electricity rates for 2009 reflect the impact of ongoing investment in electrical infrastructure and an allowed ROE of 8.87 per cent compared to 9.02 per cent for 2008.
Earnings: FortisBC's earnings were comparable quarter over quarter. The impact of the increases in electricity rates, customer growth and a lower effective corporate income tax rate was offset by: (i) higher energy supply costs associated with increased electricity sales and the impact of higher average prices for purchased power; (ii) increased amortization costs associated with continued investment in capital assets; (iii) increased operating expenses due to higher property taxes and water and wheeling fees; and (iv) higher finance charges reflecting increased debt levels in support of the Company's significant capital expenditure program, partially offset by the impact of lower interest rates on credit facility borrowings.
Earnings increased $2 million year to date compared to the same period last year. The impact of the increases in electricity rates, customer growth and a lower effective corporate income tax rate was partially offset by: (i) higher energy supply costs due to the same factors described above for the quarter, combined with a higher proportion of purchased power versus energy generated from Company-owned hydroelectric generating plants and the receipt of $0.6 million of insurance proceeds during the second quarter of 2008 associated with a turbine failure in 2006; (ii) higher operating expenses, for the reasons described above for the quarter, in addition to the impact of the timing of maintenance projects during 2009, higher labour costs and general inflationary cost increases; (iii) increased amortization costs, due to the same factor described above for the quarter; and (iv) higher finance charges, due to the same factors described above for the quarter, combined with increased credit facility renewal fees.
The decrease in the effective corporate income tax rate was due to higher deductions taken for tax purposes compared to accounting purposes combined with a lower statutory income tax rate.
In June 2009, FortisBC issued 30-year $105 million 6.10% unsecured debentures, under a short-form base shelf prospectus filed in May 2009 for the issuance of up to $300 million in debentures from time to time during the 25-month life of the shelf prospectus. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to FortisBC, refer to the "Regulatory Highlights" section of this MD&A.
Newfoundland Power
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Newfoundland Power
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Electricity Sales
(GWh) 885 897 (12) 3,825 3,796 29
--------------------------------------------------------------------------
($ millions)
--------------------------------------------------------------------------
Revenue 93 94 (1) 381 378 3
--------------------------------------------------------------------------
Energy Supply Costs 50 51 (1) 247 243 4
--------------------------------------------------------------------------
Operating Expenses 12 11 1 39 38 1
--------------------------------------------------------------------------
Amortization 12 11 1 34 33 1
--------------------------------------------------------------------------
Finance Charges 8 8 - 25 25 -
--------------------------------------------------------------------------
Corporate Taxes 4 5 (1) 12 15 (3)
--------------------------------------------------------------------------
Earnings 7 8 (1) 24 24 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales: Electricity sales at Newfoundland Power decreased 12 GWh, or 1.3 per cent, quarter over quarter, due to lower average consumption, partially offset by the impact of customer growth. Electricity sales increased 29 GWh, or 0.8 per cent, year to date compared to the same period last year, primarily due to the impact of customer growth, partially offset by lower average consumption.
Revenue: Revenue was $1 million lower quarter over quarter due to lower amortization to revenue of certain regulatory liabilities, in accordance with prescribed regulatory orders, and lower electricity sales. Revenue was $3 million higher year to date compared to the same period last year, driven by increased electricity sales, partially offset by lower amortization to revenue of certain regulatory liabilities, as described above for the quarter. The allowed ROE of 8.95 per cent for 2009 remains unchanged from 2008 and, consequently, there has been no change in basic customer rates for 2009.
Earnings: Newfoundland Power's earnings were $1 million lower quarter over quarter mainly due to higher operating expenses, driven by the timing of vegetation management costs and wage and inflationary increases, and higher amortization costs, driven by a change in the quarterly allocation of those costs and the impact of continued investment in capital assets, partially offset by the impact of a lower effective corporate income tax rate. For 2009, amortization is being allocated each quarter based on capitalized assets in service. In 2008, amortization was allocated each quarter based on sales margin.
Year to date, earnings were comparable to the same period last year. Higher electricity sales and the impact of a lower effective corporate income tax rate was largely offset by: (i) the impact of higher demand charges from Newfoundland and Labrador Hydro Corporation ("Newfoundland Hydro"), associated with meeting peak load requirements during the winter season; (ii) higher operating expenses mainly due to the same factors described above for the quarter; (iii) and increased amortization costs driven by the impact of continued investment in capital assets.
The decrease in the effective corporate income tax rate was primarily due to higher deductions taken for tax purposes compared to accounting purposes in 2009 compared to 2008 and a lower statutory income tax rate.
In May 2009, Newfoundland Power privately placed 30-year $65 million 6.606% first mortgage sinking fund bonds. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Newfoundland Power, refer to the "Regulatory Highlights" section of this MD&A.
Other Canadian Electric Utilities
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Other Canadian Electric Utilities (Unaudited) (1)
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Electricity Sales
(GWh) 514 532 (18) 1,613 1,639 (26)
--------------------------------------------------------------------------
($ millions)
--------------------------------------------------------------------------
Revenue 69 66 3 202 197 5
--------------------------------------------------------------------------
Energy Supply Costs 46 44 2 133 133 -
--------------------------------------------------------------------------
Operating Expenses 7 7 - 21 21 -
--------------------------------------------------------------------------
Amortization 5 4 1 14 13 1
--------------------------------------------------------------------------
Finance Charges 4 4 - 13 13 -
--------------------------------------------------------------------------
Corporate Taxes 2 2 - 7 6 1
--------------------------------------------------------------------------
Earnings 5 5 - 14 11 3
--------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales: Electricity sales at Other Canadian Electric Utilities decreased 18 GWh, or 3.4 per cent, quarter over quarter, and decreased 26 GWh, or 1.6 per cent, year to date compared to the same period last year driven by lower average consumption, mainly due to weather conditions experienced in Ontario and the impact of a general economic slowdown.
Revenue: Revenue increased $3 million quarter over quarter driven by the impact of an average 5.3 per cent increase in customer electricity rates at Maritime Electric, effective April 1, 2009; a 5.1 per cent and an 11.7 per cent increase in customer electricity distribution rates in Fort Erie and Gananoque, respectively, effective May 1, 2009; and the flow through to customers of higher energy supply costs at FortisOntario. The increases were partially offset by the impact of lower electricity sales at FortisOntario. The higher customer electricity rates at Maritime Electric reflect an increase in the amount of energy-related costs being collected from customers through the basic rate component of customer billings.
Revenue increased $5 million year to date compared to the same period last year. Excluding an approximate $3 million ($2 million after-tax) one-time charge at FortisOntario associated with the repayment, during the second quarter of 2008, of a refund received during the fourth quarter of 2007 associated with cross-border transmission interconnection agreements, revenue increased $2 million. The increases in customer rates at Maritime Electric and FortisOntario, as described above for the quarter, were partially offset by the impact of lower electricity sales and the flow through to customers of lower energy supply costs at FortisOntario.
Earnings: Earnings were comparable quarter over quarter and $3 million higher year to date compared to the same period last year. Excluding the $2 million after-tax one-time charge at FortisOntario associated with the repayment, during the second quarter of 2008, of the interconnection agreement-related refund, earnings increased $1 million year to date compared to the same period last year, reflecting stable operating conditions.
In June 2009, FortisOntario acquired a 10 per cent interest in Grimsby Power Inc. ("Grimsby Power") for approximately $1 million. Grimsby Power is a regulated electric distribution utility serving approximately 10,000 customers in a service territory in close proximity to FortisOntario's operations in Fort Erie.
In October 2009, FortisOntario acquired Great Lakes Power Distribution Inc., subsequently renamed Algoma Power Inc. ("Algoma Power"), for an aggregate purchase price of $75 million, including cash acquired, subject to adjustment. Algoma Power is a regulated electric distribution utility serving approximately 12,000 customers in the district of Algoma in northern Ontario.
For a discussion of the nature of regulation and material regulatory decisions and applications pertaining to Maritime Electric and FortisOntario, refer to the "Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CARIBBEAN
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Regulated Electric Utilities - Caribbean (1)
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
2009 2008(2) Variance 2009 2008(2) Variance
--------------------------------------------------------------------------
Average US:CDN
Exchange Rate (3) 1.10 1.04 0.06 1.16 1.02 0.14
--------------------------------------------------------------------------
Electricity
Sales (GWh) 312 304 8 852 838 14
--------------------------------------------------------------------------
($ millions)
--------------------------------------------------------------------------
Revenue 89 96 (7) 254 249 5
--------------------------------------------------------------------------
Energy Supply Costs 51 60 (9) 142 164 (4) (22)
--------------------------------------------------------------------------
Operating Expenses 13 12 1 41 35 6
--------------------------------------------------------------------------
Amortization 9 8 1 29 23 6
--------------------------------------------------------------------------
Finance Charges 5 4 1 13 11 2
--------------------------------------------------------------------------
Corporate Taxes - 1 (1) 1 1 -
--------------------------------------------------------------------------
Non-Controlling
Interest 4 4 - 8 6 2
--------------------------------------------------------------------------
Earnings 7 7 - 20 9 11
--------------------------------------------------------------------------
(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) Electricity sales and financial results for the three and nine months
ended September 30, 2008 included financial results of Caribbean
Utilities for the three and nine months ended July 31, 2008. Up to and
including the third quarter of 2008, Caribbean Utilities' financial
statements were consolidated in the financial statements of Fortis on a
two-month lag basis. In 2008, Caribbean Utilities changed its fiscal
year end from April 30th to December 31st, eliminating the previous
two-month lag in consolidating its financial results. Therefore,
electricity sales and financial results for the third quarter and year-
to-date period ended September 30, 2009 associated with Caribbean
Utilities relate to the utility's third quarter and year-to-date period
ended September 30, 2009.
(3) The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00 equals US$1.00. The
reporting currency of Caribbean Utilities and Fortis Turks and Caicos
is the US dollar.
(4) Energy supply costs during the second quarter of 2008 included an $18
million (BZ$36 million) charge as a result of a regulatory rate
decision by the Public Utilities Commission in Belize in June 2008.
--------------------------------------------------------------------------
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Electricity Sales: Regulated Electric Utilities - Caribbean electricity sales increased 8 GWh, or 2.6 per cent, quarter over quarter and increased 14 GWh, or 1.7 per cent, year to date compared to the same period last year. Contributing to the increases was the impact of seasonality at Caribbean Utilities combined with the loss of electricity sales during the third quarter of 2008 at Fortis Turks and Caicos as a result of Hurricane Ike, which struck the Turks and Caicos Islands in early September 2008. Average temperatures experienced on Grand Cayman in July and August 2009 were higher than normal. Also, financial results for Regulated Electric Utilities - Caribbean for the three and nine months ended September 30, 2008 included financial results of Caribbean Utilities for the three and nine months ended July 31, 2008 due to the two-month lag in consolidating Caribbean Utilities' financial results prior to the fourth quarter of 2008. At Caribbean Utilities, average temperatures for the three and nine months ended September 30th are normally higher than those for the three and nine months ended July 31st. Tempering electricity sales growth for the quarter and year-to-date period was the negative impact of global economic conditions on consumption by residential customers and activities in the tourism, oil, construction and related industries. Year to date, electricity sales growth was also tempered by the impact of cooler-than-normal weather conditions in the region during the first half of 2009, which reduced air-conditioning load during that period.
Revenue: Revenue decreased $7 million quarter over quarter. Excluding an approximate $4 million favourable impact during the third quarter of 2009 of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the strengthening of the US dollar relative to the Canadian dollar compared to the same quarter last year, revenue decreased approximately $11 million quarter over quarter. The decrease was mainly due to the flow through to customers of lower energy supply costs at Caribbean Utilities, partially offset by the impact of a 2.4 per cent increase in basic electricity rates at Caribbean Utilities, effective June 1, 2009, and increased electricity sales.
Revenue increased $5 million year to date compared to the same period last year. Revenue during the first quarter of 2009 was favourably impacted by approximately $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos related to a customer rate classification matter. Excluding the above one-time item and approximately $29 million associated with favourable foreign currency translation, revenue decreased approximately $25 million year to date compared to the same period last year. The decrease was driven by the flow through to customers of lower energy supply costs at Caribbean Utilities and Fortis Turks and Caicos, partially offset by the impact of: (i) a 2.4 per cent increase in basic customer electricity rates at Caribbean Utilities, effective June 1, 2009; (ii) increased electricity sales; and (iii) an increase in the cost of power ("COP") component of the average electricity rate at Belize Electricity, effective July 1, 2008. Tempering revenue growth was the impact of: (i) a decrease in the value-added delivery ("VAD") component of the average electricity rate at Belize Electricity, effective July 1, 2008, due to a decrease in the allowed rate of return on rate base assets ("ROA"); and (ii) a change in the methodology at Belize Electricity for recording customer installation fees and the impact of refunding certain installation fees previously collected. Customer installation fees at Belize Electricity are now recorded as a capital contribution on the balance sheet rather than as revenue on the statement of earnings.
Earnings: Earnings' contribution was comparable quarter over quarter. Excluding approximately $1 million associated with favourable foreign currency translation during the third quarter of 2009, earnings' contribution was approximately $1 million lower. The impact of higher electricity sales, the 2.4 per cent rate increase at Caribbean Utilities and the favourable impact on energy supply costs during the quarter related to a change in the methodology for accruing unbilled fuel factor revenue at Fortis Turks and Caicos in 2009 was more than offset by higher operating expenses and amortization costs.
Earnings' contribution was $11 million higher year to date compared to the same period last year. Excluding: (i) a $13 million reduction in earnings during the second quarter of 2008 representing the Corporation's approximate 70 per cent share of $18 million of disallowed previously incurred fuel and purchased power costs as a result of the June 2008 regulatory rate decision at Belize Electricity; (ii) approximately $1 million associated with a favourable appeal judgment at Fortis Turks and Caicos as described above; and (iii) approximately $3 million associated with favourable foreign currency translation, earnings' contribution decreased $6 million year to date compared to the same period last year. The decline was mainly due to the lower allowed ROA at Belize Electricity, effective July 1, 2008 and higher operating expenses and amortization costs combined with the favourable impact on energy supply costs during the first half of 2008 associated with the movement in deferred fuel costs at Caribbean Utilities. Included in Caribbean Utilities' transmission and distribution ("T&D") licence is a new mechanism for the flow through to customers of the cost of fuel and oil, which eliminates favourable or adverse timing differences in fuel and oil cost recovery for reporting periods subsequent to April 30, 2008. The decrease in earnings' contribution was partially offset by the impact of higher electricity sales, the 2.4 per cent rate increase at Caribbean Utilities, the favourable impact on energy supply costs year to date related to a change in the methodology for accruing unbilled fuel factor revenue at Fortis Turks and Caicos in 2009 and decreased finance charges.
Excluding foreign currency translation impacts, operating expenses increased approximately $1 million quarter over quarter. The increase was mainly due to higher employee costs, bad debt expense, maintenance expense and legal and regulatory costs. Excluding foreign exchange impacts, operating expenses increased approximately $1 million year to date compared to the same period last year. Increased employee costs, bad debt expense, and legal and regulatory costs were partially offset by an increase in capitalized general and administrative expenses, as prescribed under Caribbean Utilities' T&D licence, effective April 2008.
Excluding foreign currency translation impacts, amortization costs increased approximately $1 million quarter over quarter and $3 million year to date compared to the same period last year due to the impact of continued investment in capital assets.
Excluding foreign currency translation impacts, finance charges were comparable quarter over quarter and decreased approximately $1 million year to date compared to the same period last year. The decrease was mainly due to increased capitalized finance costs at Caribbean Utilities, due to a change in the utility's methodology for capitalizing finance costs associated with capital assets under construction, as prescribed under the utility's T&D licence, effective April 2008. The decrease was partially offset by the impact of lower interest income earned at Belize Electricity associated with regulatory deferral accounts.
In August 2009, Caribbean Utilities met a record peak of 97.5 MW. In July 2009, Fortis Turks and Caicos met a record peak of 29.6 MW. In May 2009, Fortis Turks and Caicos commissioned two diesel-generating units, increasing the Company's generating capacity by 6 MW to 54 MW. Fortis Turks and Caicos has also entered into an agreement with a supplier to purchase two diesel-generating engines with a combined capacity of 17.5 MW for approximately US$12 million (CDN$13 million) for delivery in April 2010 and January 2011.
Reduced energy supply and firm capacity to Belize Electricity from Comision Federal de Electricidad ("CFE") of Mexico continued during the third quarter of 2009, due to repairs being performed on certain major generating plants owned by CFE. As a result, Belize Electricity has increased its energy purchases from Belize Aquaculture Limited and Hydro Maya Limited and increased its use of in-house generation in order to meet customer energy demands with little to no reserve capacity remaining available.
Caribbean Utilities privately placed 15-year US$40 million 7.50% senior unsecured notes with US$30 million placed in May 2009 and US$10 million placed in July 2009. For additional information, see the "Liquidity and Capital Resources" section of this MD&A.
In July 2009, Fortis acquired, through a wholly owned subsidiary, 768,200 Class A Ordinary Shares of Caribbean Utilities at a price of US$8.00 per share. The shares were acquired by Fortis pursuant to a private agreement which resulted in Fortis increasing its controlling ownership in Caribbean Utilities by 2.7 per cent to approximately 59 per cent held as at September 30, 2009.
For additional information on the nature of regulation and material regulatory decisions and applications pertaining to Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of this MD&A.
NON-REGULATED - FORTIS GENERATION
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Non-Regulated - Fortis Generation (1)
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Energy Sales (GWh) 98 305 (207) 496 905 (409)
--------------------------------------------------------------------------
($ millions)
--------------------------------------------------------------------------
Revenue 9 21 (12) 34 62 (28)
--------------------------------------------------------------------------
Energy Supply Costs 1 2 (1) 2 6 (4)
--------------------------------------------------------------------------
Operating Expenses 2 3 (1) 8 11 (3)
--------------------------------------------------------------------------
Amortization - 3 (3) 4 8 (4)
--------------------------------------------------------------------------
Finance Charges 1 2 (1) 3 6 (3)
--------------------------------------------------------------------------
Corporate Taxes 1 2 (1) 3 7 (4)
--------------------------------------------------------------------------
Non-Controlling
Interest - - - 1 2 (1)
--------------------------------------------------------------------------
Earnings 4 9 (5) 13 22 (9)
--------------------------------------------------------------------------
(1) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State. Prior to May 1, 2009, financial results reflected earnings'
contribution associated with the Corporation's 75-MW water-right
entitlement on the Niagara River in Ontario under the Niagara Exchange
Agreement related to the Rankine hydroelectric generating facility.
The Niagara Exchange Agreement expired on April 30, 2009, in accordance
with its terms. Prior to February 13, 2009, the financial results of
the hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. As of February 13,
2009, the financial results of the generation operations in central
Newfoundland have been recorded in the financial statements of Fortis
on an equity basis, due to the Corporation no longer having control
over the generation operations as a result of the expropriation of the
related assets by the Government of Newfoundland and Labrador. The
change in the method of accounting did not have a material impact on
segmented or consolidated earnings. Equity income for 2009 related to
central Newfoundland operations is being recorded in revenue. For a
further discussion of this matter, refer to the "Critical Accounting
Estimates - Contingencies" section of this MD&A.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Sales: Non-Regulated - Fortis Generation energy sales decreased 207 GWh, or 67.9 per cent, quarter over quarter and decreased 409 GWh, or 45.2 per cent, year to date compared to the same period last year. As anticipated, 164 GWh and 276 GWh of the decrease in energy sales quarter over quarter and year to date compared to the same period last year, respectively, was due to the expiration, on April 30, 2009, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario. In addition, energy sales year-to-date 2009 included energy sales associated with the generation operations in central Newfoundland for only 11/2 months compared to a full nine months in 2008, due to the change to the equity method of accounting for these operations in February 2009 necessitated by the actions of the Government of Newfoundland and Labrador related to its expropriation of Newfoundland-based assets of AbitibiBowater Inc., formerly Abitibi-Consolidated Company of Canada ("Abitibi"). The decrease in energy sales quarter over quarter and year to date compared to the same period last year was also due to the impact of overall lower production at all of the Corporation's other generation operations. Production levels were primarily a function of rainfall levels in addition to the impact of one unit at the Chaillio hydroelectric generating facility being off-line for maintenance for about 11/2 months during the third quarter of 2009. As at October 31, 2009, the Chalillo reservoir in Belize was near its full-supply level.
Revenue: Revenue was $12 million lower quarter over quarter and $28 million lower year to date compared to the same period in 2008. The primary factors decreasing revenue were: (i) the loss of revenue subsequent to the expiration of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility, as described above; (ii) the impact of changing to the equity method of accounting for the financial results of the hydroelectric generation operations in central Newfoundland during the first quarter of 2009, as described above; (iii) lower average wholesale market energy prices per megawatt hour ("MWh") in Upper New York State, which were US$31.37 for the third quarter of 2009 compared to US$77.82 for the same quarter in 2008 and US$37.52 year to date compared to US$77.20 for the same period in 2008; and (iv) decreased production. Revenue also decreased year to date compared to the same period last year due to lower average wholesale market energy prices per MWh in Ontario, which were $36.83 for January through April 2009 compared to $49.70 for the same period in 2008. Revenue for the quarter and year to date, however, was favourably impacted by approximately $0.5 million and $2.5 million, respectively, of foreign exchange associated with the translation of foreign currency-denominated revenue, due to the strengthening of the US dollar relative to the Canadian dollar compared to the same periods in 2008.
Earnings: Earnings decreased $5 million quarter over quarter, primarily related to the loss of earnings subsequent to the expiration of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility, lower average wholesale market energy prices in Upper New York State and decreased production in Belize. Earnings decreased $9 million year to date compared to the same period last year driven by the expiration of the power-for-water exchange agreement, lower average wholesale market energy prices in Upper New York State and Ontario and the impact of lower production in Upper New York State. Earnings for the quarter and year to date, however, were favorably impacted by approximately $0.5 million and $1.5 million, respectively, associated with foreign currency translation. Earnings' contribution associated with the Rankine hydroelectric generating facility were nil for the third quarter and $3.5 million year to date compared to approximately $4 million and $11.5 million for the respective periods in 2008.
NON-REGULATED - FORTIS PROPERTIES
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Hospitality Revenue 44 40 4 117 108 9
--------------------------------------------------------------------------
Real Estate Revenue 16 16 - 48 47 1
--------------------------------------------------------------------------
Total Revenue 60 56 4 165 155 10
--------------------------------------------------------------------------
Operating Expenses 37 33 4 109 99 10
--------------------------------------------------------------------------
Amortization 4 4 - 12 11 1
--------------------------------------------------------------------------
Finance Charges 6 6 - 17 18 (1)
--------------------------------------------------------------------------
Corporate Taxes 4 4 - 8 8 -
--------------------------------------------------------------------------
Earnings 9 9 - 19 19 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue: Hospitality revenue was $4 million higher quarter over quarter and $9 million higher year to date compared to the same period last year, driven by revenue contribution from the Sheraton Hotel Newfoundland, which was acquired in November 2008, and the Holiday Inn Select in Windsor, Ontario, which was acquired in April 2009 for $7 million, partially offset by decreased revenue from operations in Ontario and western Canada.
Revenue per available room was $89.02 for the third quarter compared to $93.64 for the same quarter in 2008, and $79.19 year to date compared to $83.04 for the same period last year. The decreases were mainly due to lower hotel occupancies in all of the Company's operating regions, the most significant of which were experienced in Ontario and western Canada.
Real Estate revenue was comparable quarter over quarter and $1 million higher year to date compared to the same period last year. The year-to-date increase included a one-time lease termination fee associated with a tenant in New Brunswick. The occupancy rate of the Real Estate Division was 96.2 per cent as at September 30, 2009 compared to 96.6 per cent as at September 30, 2008. The decrease in the occupancy rate was primarily associated with a property in rural Newfoundland.
Earnings: Earnings were comparable quarter over quarter. Contribution by the Sheraton Hotel Newfoundland and the Holiday Inn Select in Windsor combined with increased contribution from the Real Estate Division were offset by the impact of generally lower occupancies at the remainder of the Company's hotels. Earnings were also comparable year to date over the same period last year. Contribution by the newly acquired hotels, as described above, combined with increased contribution from the Real Estate Division and lower finance charges was offset by the impact of generally lower occupancies at the remainder of the Company's hotels. Finance charges decreased mainly due to the reduction of principal balances on external debt resulting from regularly scheduled debt repayments.
Operating expenses were $4 million higher quarter over quarter and $10 million higher year to date compared to the same period last year. The increases were primarily related to the Sheraton Hotel Newfoundland, including non-recurring transitional operating costs incurred during the first quarter of 2009, and the Holiday Inn Select in Windsor. The increases were partially offset by overall cost reductions realized in the balance of the Hospitality Division and lower operating expenses incurred at the Real Estate Division. The decrease in operating expenses incurred at the Real Estate Division mainly related to the reclassification to amortization costs during 2009 of certain major operating expenses recoverable from tenants, which were previously deferred and amortized to operating expenses.
CORPORATE AND OTHER
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Corporate and Other (1)
Financial Highlights (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Revenue 7 7 - 21 19 2
--------------------------------------------------------------------------
Operating Expenses 2 2 - 9 8 1
--------------------------------------------------------------------------
Amortization 2 2 - 7 6 1
--------------------------------------------------------------------------
Finance Charges (2) 21 19 2 58 60 (2)
--------------------------------------------------------------------------
Corporate Tax Recovery (6) (6) - (15) (15) -
--------------------------------------------------------------------------
Preference Share
Dividends 5 5 - 14 9 5
--------------------------------------------------------------------------
Net Corporate and
Other Expenses (17) (15) (2) (52) (49) (3)
--------------------------------------------------------------------------
(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 Terasen Energy Services Inc.
(2) Includes dividends on preference shares classified as long-term
liabilities
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue: Revenue was comparable quarter over quarter and $2 million higher year to date compared to the same period last year, driven by higher inter-company interest revenue due to increased inter-company lending.
Net Corporate and Other Expenses: Net corporate and other expenses were $2 million higher quarter over quarter. Excluding a $1 million favourable corporate tax adjustment at Fortis during the third quarter of 2009 and a $2 million tax reduction recorded in the third quarter of 2008, associated with the settlement of historical corporate tax matters at Terasen, net corporate and other expenses were $1 million higher quarter over quarter. The increase was driven by higher finance charges associated with the 30-year $200 million 6.51% unsecured debentures that were issued in July 2009.
Net corporate and other expenses were $3 million higher year to date compared to the same period last year. Excluding the one-time items in 2009 and 2008 related to corporate taxes, as described above for the quarter, net corporate and other expenses were $2 million higher year to date compared to the same period last year. The increase was due to higher preference share dividends, due to the issuance of First Preference Shares, Series G during the second quarter of 2008, and lower earnings' contribution from CustomerWorks Limited Partnership, partially offset by lower finance charges and higher inter-company interest revenue.
Finance charges decreased year to date compared to the same period last year as a result of overall lower debt levels during the first half of 2009 compared to the same period last year and lower interest rates charged on credit facility borrowings. The decrease was partially offset by higher finance charges associated with the $200 million unsecured debentures issued in July 2009 and the unfavourable impact of foreign exchange associated with the translation of US dollar-denominated interest expense.
In December 2008, Fortis completed a $300 million common share issue, the net proceeds of which were primarily used to repay short-term debt incurred to repay maturing long-term debt.
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
---------------------------------------------------------------------------
Allowed Returns (%) Supportive Features
Allowed ------------------ --------------------
Common Future or Historical
Regulated Regulatory Equity Test Year Used to
Utility Authority (%) 2007 2008 2009 Set Rates
---------------------------------------------------------------------------
ROE Cost of Service
("COS")/ROE
----------------------
TGI British 35 8.37 8.62 8.47 PBR mechanism
Columbia through 2009: TGI
Utilities : 50/50 sharing
Commission of earnings above
("BCUC") or below the allowed
ROE
TGVI BCUC 40 9.07 9.32 9.17 TGVI: 100 per cent
retention of
earnings from lower-
than-forecasted
operating and
maintenance costs
but no relief from
increased operating
and maintenance
costs
ROE automatic
adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
FortisBC BCUC 40 8.77 9.02 8.87 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 automatic
adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Fortis- Alberta 37 8.51 8.75 8.51(1) COS/ROE
Alberta Utilities
Commission ROE automatic
("AUC") adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Newfound- Newfound- 45 8.60 8.95 8.95 COS/ROE
land land +/- +/- +/-
Power and 50 bps 50 bps 50 bps ROE automatic
Labrador adjustment formula
Board of tied to long-term
Commis- Canada bond yields
sioners of --------------------
Public Future Test Year
Utilities
("PUB")
---------------------------------------------------------------------------
Maritime Island 40 10.25 10.00 9.75 COS/ROE
Electric Regulatory --------------------
and Appeals Future Test Year
Commission
("IRAC")
---------------------------------------------------------------------------
Fortis- Ontario 43.3 9.00 9.00 8.01 Canadian Niagara
Ontario Energy Power - COS/ROE
Board
("OEB") Cornwall Electric -
(Canadian Price cap with
Niagara commodity cost flow
Power) through
--------------------
Franchise Future Test Year -
Agreement Beginning in 2009
(Cornwall
Electric)
---------------------------------------------------------------------------
ROA Four-year COS/ROA
Belize Public ----------------------- agreements
Electri- Utilities 10.00- 10.00 10.00(2)
city Commission N/A 15.00 Additional costs in
("PUC") the event of a
hurricane would be
deferred and the
Company may apply
for future recovery
in customer rates.
--------------------
Future Test Year
---------------------------------------------------------------------------
Carib- Electricity N/A 15.00 9.00- 9.00- COS/ROA
bean Regulatory 11.00 11.00
Utilities Authority Rate-cap adjustment
("ERA") mechanism based on
published consumer
price indices
Under the new T&D
licence, the Company
may apply for a
special additional
rate to customers in
the event of a
disaster, including
a hurricane.
--------------------
Historical Test Year
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Fortis Utility N/A 17.50 17.50 17.50(3) COS/ROA
Turks makes (3) (3)
and annual If the actual ROA
Caicos filings is lower than the
with the allowed ROA, due to
Energy additional costs
Commissioner resulting from a
hurricane or other
event, the Company
may apply for an
increase in customer
rates in the
following year.
--------------------
Future Test Year
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(1) Interim ROE pending the outcome of the AUC's 2009 Generic Cost of
Capital Proceeding
(2) Based on the June 2008 Final Decision related to Belize Electricity's
2008/2009 Rate Application
(3) Amount provided under licence. Actual ROAs achieved in 2007 and 2008
were significantly lower than the ROA allowed under the licence due to
significant investment occurring at the utility.
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Material Regulatory Decisions and Applications
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Regulated Utility Summary Description
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TGI/TGVI - Every three months, TGI and TGVI review natural gas and
propane commodity prices with the BCUC in order to
ensure the flow-through rates charged to customers are
sufficient to cover the cost of purchasing natural gas
and propane. As approved by the BCUC, the commodity
rate for natural gas was unchanged during the first
quarter of 2009 while the commodity rate for propane
decreased, effective January 1, 2009. Effective April
1, 2009, the BCUC approved decreases in the commodity
rates for natural gas and propane. Effective July 1,
2009, the BCUC approved the commodity rate for natural
gas as unchanged for customers in most service regions
and approved an increase in the commodity rate for
propane for customers in Revelstoke. Effective October
1, 2009, the BCUC approved decreases in the commodity
rate for natural gas for customers in the Lower
Mainland, Fraser Valley and Interior regions. The
commodity cost of natural gas and propane is flowed
through to customers without markup.
- In December 2008, the BCUC approved a basic customer
delivery rate increase of approximately 6 per cent at
TGI and approved basic customer delivery rate increases
up to 5 per cent at TGVI based on customer rate class.
Basic customer delivery rates for 2009 reflect the
decrease in the allowed ROE for 2009 at TGI and TGVI to
8.47 per cent and 9.17 per cent, respectively,
resulting from the application of automatic ROE
adjustment mechanisms.
- In March 2009, TGI received approval for its
application with the BCUC to perform extensive
rehabilitation of certain underwater transmission
pipeline crossings of the South Arm of the Fraser
River, serving Vancouver and Richmond. The project is
expected to be completed in 2010 for a total cost of
approximately $27 million.
- In April 2009, TGI received approval from the BCUC for
its new $41.5 million Energy Efficiency and
Conservation Program to provide customers with enhanced
tools and incentives to manage their natural gas
consumption, reduce their energy costs and lower their
greenhouse gas emissions. The program began in summer
2009.
- In June 2009, the BCUC approved TGI's application
requesting to sell liquefied natural gas as a
transportation fuel source for fleet vehicles.
- In May 2009, the Terasen Gas companies filed an
application with the BCUC requesting a review of the
current generic allowed ROE adjustment mechanism and
the deemed equity component of the capital structure
for TGI. The application contemplates an increase in
TGI's allowed ROE to 11 per cent from 8.47 per cent,
effective July 1, 2009, and an increase in the allowed
common equity component of TGI's capital structure to
40 per cent from 35 per cent, effective January 1,
2010. No change was requested in the risk-premium
spread of 70 basis points over TGI's allowed ROE in
determining TGVI's allowed ROE. A decision on the
application is expected by the end of the year or early
in 2010.
- In June 2009, TGI applied to the BCUC for in-sourcing
of core elements of its customer care services and for
implementation of a new customer information system.
If approved, the new model would be in place effective
January 2012 at a total expected capital cost of
approximately $120 million, including amounts to
regulatory deferral accounts. TGI has requested a
decision on this project by the end of 2009.
- Effective June 1, 2009, the BCUC approved an average 12
per cent decrease in basic customer delivery rates at
TGWI. Effective July 1, 2009, the BCUC also approved
an approximate 10 per cent decrease in commodity rates
at TGWI.
- In June 2009, TGI and TGVI each filed with the BCUC
two-year revenue requirements applications for 2010 and
2011. The current PBR agreements at TGI and TGVI
expire on December 31, 2009. The rate applications
will be updated to reflect the amounts to be approved
by the BCUC with respect to an increase in the deemed
equity level at TGI and the allowed ROEs as filed with
the BCUC in May 2009, as described above. TGI's
application assumes forecast average rate base of
approximately $2,536 million and $2,620 million for
2010 and 2011, respectively, while TGVI's application
assumes forecast average rate base of approximately
$555 million and $730 million for 2010 and 2011,
respectively. The expected overall impact on customer
rates at TGI for 2010 and 2011, including the flow
through of the cost of natural gas but before any
effect of an increase in the deemed equity level and
the allowed ROE, is an increase of approximately 3 per
cent and 2 per cent, respectively. TGVI is requesting
customer rates for its sales customers, including the
flow through of the cost of natural gas but before any
effect of an increase in the allowed ROE, to remain
unchanged for the two-year period beginning January 1,
2010. TGVI, however, is requesting overall rates for
its transportation customers that are not subject to
separate transportation service agreements be decreased
by approximately 5 per cent in 2010 and remain
unchanged during 2011. Decisions on the applications
are expected by the end of the year or early in 2010.
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FortisBC - In December 2008, the BCUC approved the Company's 2009
Revenue Requirements Application, resulting in a general
rate increase of 4.6 per cent, effective January 1,
2009. The rate increase is primarily the result of the
Company's ongoing investment in electrical
infrastructure and increasing power purchase prices
driven by customer growth and increased electricity
demand. Rates for 2009 reflect an allowed ROE of 8.87
per cent as a result of the application of the automatic
ROE adjustment mechanism. The approval of the 2009
Revenue Requirements Application also included an
extension of the PBR mechanism for the years 2009
through 2011 under terms similar to the previous PBR
agreement, except annual gross operating and maintenance
expenses, before capitalized overhead, will be set by a
formula incorporating customer growth and inflation,
i.e., the consumer price index ("CPI") for British
Columbia minus a productivity improvement factor ("PIF")
of 3 per cent in 2009, 1.5 per cent in 2010 and 1.5 per
cent in 2011. Should inflation be in excess of 3 per
cent, the excess is to be added to the PIF, which
effectively caps the CPI at 3 per cent.
- In February 2009, the BCUC issued its decision on
FortisBC's 2009 and 2010 Capital Expenditure Plan.
Total gross capital expenditures of $165 million and
$156 million were approved for 2009 and 2010,
respectively.
- In August 2009, FortisBC applied for and received BCUC
approval for a 2.2 per cent increase in customer rates,
effective September 1, 2009. The increase was due to
higher power purchase costs being charged to the Company
by BC Hydro.
- In October 2009, FortisBC filed its Preliminary 2010
Revenue Requirements Application requesting a 4.6 per
cent general customer rate increase, effective January
1, 2009. The requested rate increase is due to the
Company's ongoing investment in electrical
infrastructure and increasing power purchase prices
driven by customer growth and increased electricity
demand.
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FortisAlberta - In June 2008, the AUC ruled that a review of ROE levels,
adjustment mechanisms and utility capital structures in
a generic proceeding would be appropriate. In July
2008, the AUC issued its notice of application,
preliminary scoping document and minimum filing
requirements for the 2009 Generic Cost of Capital
Proceeding. The proceeding applies to all gas, electric
and pipeline utilities in Alberta that are regulated by
the AUC.
- In November 2008, FortisAlberta submitted its evidence
with respect to the 2009 Generic Cost of Capital
Proceeding as requested by the AUC. Oral hearings took
place in May and June 2009, arguments were provided in
July and August 2009 and an AUC order is expected during
the fourth quarter of 2009.
- In December 2008, FortisAlberta received regulatory
approval for its 2009 distribution rates to recover
approved distribution costs. The result was a
distribution rate increase of 8.6 per cent, effective
January 1, 2009. The rate increase was slightly higher
than the rate increase of 7.3 per cent contemplated in
the 2008/2009 Negotiated Settlement Agreement ("NSA"),
due to the deferred recovery in customer rates in 2009
of the increase in the allowed ROE to 8.75 per cent in
2008. The approved rates for 2009 also reflect the
impact of the Company's union agreement, which was
settled after the 2008/2009 NSA was approved. As
directed by the AUC, the Company is to continue using
the 2007 allowed ROE of 8.51 per cent for 2009, pending
the outcome of the 2009 Generic Cost of Capital
Proceeding.
- In June 2009, FortisAlberta filed a comprehensive two-
year distribution revenue requirements application for
2010 and 2011. For both years, the application assumes
an interim allowed ROE of 8.75 per cent with a deemed
equity level of 37 per cent, pending the outcome of the
current Generic Cost of Capital Proceeding. The
application also forecasts average rate base of
approximately $1,538 million and $1,724 million for 2010
and 2011, respectively. The expected impact on the
distribution component of customer rates for 2010 and
2011 is an average increase of 13.3 per cent and 14.9
per cent, respectively. FortisAlberta anticipates a
hearing in November 2009, a regulatory decision by the
AUC to be received in spring 2010 with final customer
rates anticipated to take effect late in 2010 or early
2011. An application for interim rates, effective
January 2010, was filed in October 2009.
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Newfoundland - In November 2008, the PUB approved, as filed, the
Power Company's 2009 Capital Budget Application for
approximately $62 million, with approximately half of
the proposed capital expenditures relating to
construction and capital maintenance of the electricity
system. During the third quarter of 2009, Newfoundland
Power filed supplemental applications to its 2009
Capital Budget Application, requesting an additional
approximate $2 million in capital spending, which were
approved by the PUB.
- The Company's allowed ROE of 8.95 per cent remains
unchanged for 2009 and, consequently, there has been no
change in basic customer rates for 2009.
- Effective July 1, 2009, the PUB approved an overall
average decrease in customer electricity rates of
approximately 6.6 per cent, reflecting the flow through
to customers, by operation of the Rate Stabilization
Account, of variances in the cost of fuel used to
generate electricity that Newfoundland Hydro sells to
Newfoundland Power. The decrease in customer rates will
have no impact on Newfoundland Power's earnings in 2009.
- In November 2009, the Company's 2010 Capital Budget
Application totalling approximately $65 million was
approved by the PUB.
- In September 2009, Newfoundland Power filed a revised
2010 General Rate Application, seeking approval for an
overall average increase in basic customer electricity
rates of approximately 7.2 per cent, effective January
1, 2010. The proposed increase in rates is the result
of a full review of the Company's costs and customer
rates. The application seeks an increase in the allowed
ROE from 8.95 per cent to 11 per cent for 2010 on an
equity level of approximately 45 per cent. The
application also forecasts average rate base of
approximately $869 million for 2010. A public hearing
on the application occurred in October 2009.
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Maritime - In March 2009, IRAC approved Maritime Electric's
Electric 2009 Rate Application, which resulted in an increase in
the amount of energy-related costs being collected from
customers through the basic rate component of customer
billings, effective April 1, 2009. The increase in the
reference cost of energy in basic rates from 6.73 cents
per kilowatt hour ("kWh") to 7.7 cents per kWh results
in a decrease in the amount of energy costs to be
collected from customers through the operation of the
Energy Cost Adjustment Mechanism ("ECAM").
Additionally, IRAC approved the deferral of New
Brunswick Power Point Lepreau Nuclear Generating Station
("Point Lepreau") replacement energy costs for 2009 and
an increase in the amortization period of the ECAM to 12
months, effective April 1, 2009. IRAC also approved, as
filed, a maximum allowed ROE of 9.75 per cent for 2009,
down from an allowed ROE of 10.00 per cent for 2008.
The overall impact on residential customer rates for
2009 is an increase of 5.3 per cent based on average
consumption of 650 kWh per month.
- In September 2009, New Brunswick Power announced that
the refurbishment of Point Lepreau is behind schedule
with the target date for electricity to be generated
again delayed until February 2011. The Point Lepreau
reactor was originally scheduled to restart October 1,
2009.
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FortisOntario - In August 2008, Canadian Niagara Power filed a 2009 Cost
of Service Application ("2009 Application") requesting
the rebasing of distribution rates using 2009 as a
forward test year. In August 2009, the OEB issued its
Rate Order on the 2009 Application for Fort Erie and
Gananoque, approving final distribution rate increases,
effective May 1, 2009, of 5.1 per cent and 11.7 per
cent, respectively, with impact on customer billings
commencing September 1, 2009. Foregone revenue from May
1, 2009 through August 31, 2009 will be recovered from
customers through a rate rider in effect from September
1, 2009 through April 30, 2010. The Rate Order
confirmed a deemed capital structure containing 43.3 per
cent equity, consistent with that assumed in the 2009
Application, approved an allowed ROE of 8.01 per cent
for 2009 and approved all forecast capital expenditures
and significantly all forecast operating expenses, as
filed. The approved rate increases were primarily
driven by the impact of distribution system upgrades.
- In March 2009, the OEB announced that it was initiating
a consultative process with utilities in Ontario that it
regulates to help the OEB determine whether current
economic and financial market conditions warrant an
adjustment to any cost of capital parameter values
determined in accordance with current established
methodology. In June 2009, the OEB issued a letter
indicating that it had decided not to change the
parameters for 2009. A stakeholder conference was held
in September and October 2009 to review the cost of
capital policy for future years. The OEB anticipates
that any policy changes made as a result of the review
process will apply to the setting of rates for the 2010
rate year.
- In September 2009, the OEB issued a Decision on the 2009
Application for Port Colborne, effective May 1, 2009,
with impact on customer billings commencing November 1,
2009. Foregone revenue from May 1, 2009 through October
31, 2009 will be permitted to be collected from
customers. The Decision confirmed a similar capital
structure and allowed ROE as for Fort Erie and
Gananoque. A draft Rate Order for Port Colborne was
filed in October 2009 and a Final Rate Order from the
OEB is expected in the fourth quarter of 2009.
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Belize - In June 2008, the PUC issued its Final Decision
Electricity on Belize Electricity's 2008/2009 Rate Application,
which rejected most of the recommendations of a PUC-
appointed Independent Expert engaged to review the PUC's
Initial Decision on Belize Electricity's 2008/2009 Rate
Application and failed to increase the overall average
electricity rate as requested in the application. The
PUC also ordered a BZ$36 million retroactive adjustment
associated with Belize Electricity's prior years'
financial results. The adjustment, in substance,
represented the disallowance of previously incurred fuel
and purchased power costs. The PUC also reduced Belize
Electricity's targeted allowed ROA to 10 per cent from
12 per cent through a reduction in the VAD component of
the average electricity rate. As a direct result of the
June 2008 Final Decision, Belize Electricity recorded
an $18 million (BZ$36 million) charge ($13 million of
which was the Corporation's share) to energy supply
costs during the second quarter of 2008. The Final
Decision does not impact the Corporation's hydroelectric
generation operations conducted in Belize Electric
Company Limited ("BECOL").
- The Final Decision also proposed the use of an automatic
mechanism, to be finalized by the PUC, to adjust
monthly, on a two-month lag basis, the cost of power
component of the rate to reflect actual costs of power.
The automatic adjustment mechanism, which was
retroactively effective September 1, 2008, allows for
the collection from, or rebate to, customers of actual
costs of power which vary from a reference cost of power
by more than a threshold of 10 per cent.
- In February 2009, the PUC amended the Final Decision on
Belize Electricity's 2008/2009 Rate Application (the
"Amendment"), effective for the period from January 1,
2009 through June 30, 2009. The Amendment provides for
an increase in the VAD component of the average
electricity rate to allow Belize Electricity to earn a
targeted allowed ROA of 12 per cent but reduces the
reference COP component of the average electricity rate,
due to an overall decline in the cost of power. The
Amendment, therefore, allows for an overall decrease in
the average electricity rate from BZ44.1 cents per kWh
to BZ37.5 cents per kWh. The Amendment also provides
for a lower regulated asset value upon which the allowed
ROA is calculated, while increasing operating expenses
by the same amount, and reduces depreciation, taxes and
fees and the related revenue requirement.
- In April 2009, Belize Electricity filed its Annual
Tariff Review Application for the annual tariff period
from July 1, 2009 to June 30, 2010 ("2009/2010 Rate
Application") proposing a 6 per cent decrease in the
average electricity rate, as well as a reversal of the
BZ$36 million charge described above. The PUC has not
accepted the 2009/2010 Rate Application on the grounds
that an Annual Tariff Review Proceeding is not in
effect.
- Changes made in electricity legislation by the
Government of Belize and the PUC, and the June 2008
Final Decision and 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. However, the
Supreme Court of Belize has approved an injunction
against the Amendment until Belize Electricity's appeal
of the June 2008 Final Decision has been heard in court,
which commenced early October 2009, but after
considering some preliminary matters the trial judge
postponed the case for a date to be determined. In
addition, Belize Electricity's appeal of the Supreme
Court of Belize's previous decision to uphold certain
changes made in electricity legislation by the
Government of Belize and the PUC was dismissed in June
2009.
- In June 2009, the Minister of Public Utilities of Belize
issued a statutory instrument purporting to declare
providers of electricity generation and water services,
including BECOL, as public utility providers within the
meaning of the Public Utilities Commission Act as of May
1, 2009. Fortis is currently assessing the statutory
instrument and its impact on previously negotiated and
PUC-approved power purchase agreements.
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Caribbean - In January 2009, a revised Five-Year Capital Investment
Utilities Plan ("CIP") totalling US$246 million was submitted to
the ERA. In March 2009, the ERA approved the Company's
2009 CIP of US$48 million. In October 2009, Caribbean
Utilities submitted to the ERA a CIP totalling US$157
million for the period 2010 through 2014.
- In April 2009, Caribbean Utilities submitted its bid to
install 16 MW of generation in May 2012 and another 16
MW of generation in May 2013. There was one other
bidder for the 32 MW of generation. Based on current
economic conditions and revised medium-term future load
growth projections by the Company, the ERA has cancelled
its 32 MW capacity-expansion solicitation. Caribbean
Utilities and the ERA will continue to monitor growth
indicators and revise forecasts as necessary. A new
solicitation may occur at such time there are indicators
of a future need for additional capacity. Caribbean
Utilities' CIP for 2010 through 2104 reflects the
Company's lower growth projections and delay of the 32
MW of new generating capacity.
- The ERA approved a 2.4 per cent increase in basic
customer electricity rates, effective June 1, 2009, in
accordance with the rate adjustment mechanism provided
under Caribbean Utilities' T&D licence.
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Fortis Turks - In March 2009, Fortis Turks and Caicos submitted its
and Caicos 2008 annual regulatory filing outlining the Company's
performance in 2008 and its capital expansion plans for
2009.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated
balance sheets between September 30, 2009 and December 31, 2008.
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Fortis Inc.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between September 30, 2009 and December 31, 2008
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Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
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Cash and cash 40 The increase was primarily due to cash on hand
equivalents associated with partial proceeds from the $200
million debenture offering at Fortis in July
2009. Subsequent to the quarter end, a
portion of the proceeds were used to help
initially finance the acquisition of Great
Lakes Distribution Power Inc. The remaining
increase in cash was due to higher cash
balances at Newfoundland Power, driven by the
timing of long-term debt interest and sinking
fund payments.
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Accounts receivable (324) The decrease was primarily due to the impact
of a seasonal decrease in sales, driven by the
Terasen Gas companies and Newfoundland Power,
and the impact of lower fuel factor billings
at Caribbean Utilities and Fortis Turks and
Caicos associated with a decline in fuel
prices.
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Regulatory assets 564 The increase was primarily due to the result
- current and long of recording $543 million in regulatory assets
-term as at September 30, 2009, associated with the
recognition of future income taxes upon
adoption of amended Section 3465, Income
Taxes, effective January 1, 2009. The
remainder of the increase was mainly due to
the regulatory deferral associated with the
change in the fair market value of the gas
commodity swap and option contracts at the
Terasen Gas companies and the deferral of
Point Lepreau energy replacement costs at
Maritime Electric. The increase was partially
offset by the impact of the deferral of
amounts collected in customer rates in excess
of the actual commodity cost of natural gas at
the Terasen Gas companies year-to-date 2009.
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Other assets (58) The decrease was driven by a net $61 million
reduction associated with the change to the
equity method of accounting of the
Corporation's interest in the Exploits River
Hydro Partnership ("Exploits Partnership"),
effective February 13, 2009. Previously, the
financial results of the Exploits Partnership
were consolidated in the financial statements
of the Corporation. Refer to the "Critical
Accounting Estimates - Contingencies" section
of this MD&A for a further discussion of the
Exploits Partnership.
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Utility capital 347 The increase primarily related to $725 million
assets invested in electricity and gas systems,
partially offset by amortization and customer
contributions for the nine months ended
September 30, 2009 and the impact of foreign
exchange on the translation of foreign
currency-denominated utility capital assets.
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Short-term borrowings (74) The decrease was driven by the repayment of
short-term borrowings by TGI and Caribbean
Utilities with partial proceeds from the
issuances of long-term debt, repayment of
short-term borrowings by Fortis Turks and
Caicos with proceeds from inter-company
borrowings with Fortis, combined with lower
borrowings at the Terasen Gas companies due to
seasonality of operations.
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Accounts payable (162) The decrease was driven by lower amounts
and accrued owing for purchased gas at the Terasen Gas
charges companies and purchased power at Newfoundland
Power due to seasonality of operations, and
the timing of payment of property taxes and
franchise fees at the Terasen Gas companies,
partially offset by a $34 million increase
associated with the change in the fair market
value of gas commodity swap and option
contracts at the Terasen Gas companies.
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Income taxes payable (56) The decrease was mainly due to the timing of
income tax payments at the Terasen Gas
companies and Newfoundland Power.
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Regulatory 40 The increase was primarily due to the result
liabilities - of recording $41 million in regulatory
current and long- liabilities as at September 30, 2009,
term associated with the recognition of future
income taxes upon adoption of amended Section
3465, Income Taxes, effective January 1, 2009.
Regulatory liabilities also increased due to
the lower cost of fuel and purchased power at
Belize Electricity year-to-date 2009 compared
to amounts collected in customer rates during
the same time period. The increase was
partially offset by lower rate stabilization
account balances at the Terasen Gas companies
associated with the impact of the deferral of
actual mid-stream gas-delivery costs in excess
of amounts collected in customer rates,
partially offset by the deferral of the margin
impact of actual customer consumption
exceeding forecast consumption year-to-date
2009.
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Future income tax 487 The increase was primarily due to the
liabilities - recognition of future income taxes
current and long- upon adoption of amended Section 3465,
term Income Taxes, effective January 1, 2009.
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Deferred credits 31 The increase was primarily due to the
reclassification of $19 million to future
income taxes upon adoption of amended Section
3465, Income Taxes, effective January 1, 2009.
Such taxes were previously netted against
other post-employment benefit obligations at
the Terasen Gas companies. Also contributing
to the increase was an increase in defined
benefit pension and other post-employment
benefit obligations.
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Long-term debt and 250 The increase was primarily due to the issuance
capital lease of long-term debt, partially offset by a net
obligations $54 million repayment of committed credit
(including current facility borrowings and a $61 million
portion) decrease associated with the change to the
equity method of accounting of the
Corporation's interest in the Exploits
Partnership, effective February 13, 2009;
regularly scheduled debt repayments and debt
maturities; and the impact of foreign exchange
on the translation of foreign currency-
denominated debt. Previously, the financial
results of the Exploits Partnership were
consolidated in the financial statements of
the Corporation. Refer to the "Critical
Accounting Estimates - Contingencies" section
of this MD&A for a further discussion of the
Exploits Partnership.
The issuance of long-term debt year-to-date
September 2009, primarily to repay committed
credit facility borrowings, short-term
borrowings and maturing debt, was comprised of
a $100 million debenture offering by TGI, a
$100 million debenture offering by
FortisAlberta, a $65 million bond offering by
Newfoundland Power, a US$40 million note
offering by Caribbean Utilities, a $105
million debenture offering by FortisBC and a
$200 million debenture offering by Fortis.
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Non-controlling (21) The decrease primarily related to the
interest impact of foreign exchange on the translation
of US dollar-denominated non-controlling
interest amounts, combined with Fortis
increasing its controlling ownership in
Caribbean Utilities by 2.7 per cent in July
2009.
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Shareholders' equity 54 The increase was mainly due to net earnings
applicable to common shares reported for the
nine months ended September 30, 2009, less
common share dividends. The remainder of the
increase related to the issuance of common
shares under the Corporation's share purchase,
dividend reinvestment and stock option plans,
partially offset by an increase in accumulated
other comprehensive loss.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash for the three and nine months ended September 30, 2009, as compared to the same periods in 2008, followed by a discussion of the nature of the variances in cash flows.
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Fortis Inc.
Summary of Cash Flows (Unaudited)
Periods Ended September 30
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Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
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Cash, beginning of
period 137 59 78 66 58 8
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Cash provided by
(used in)
--------------------------------------------------------------------------
Operating
activities 63 27 36 567 452 115
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Investing
activities (251) (229) (22) (733) (580) (153)
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Financing
activities 159 211 (52) 209 138 71
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Foreign currency
impact on cash
balances (2) - (2) (3) - (3)
--------------------------------------------------------------------------
Cash, end of period 106 68 38 106 68 38
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Operating Activities: Cash flow from operating activities, after working capital adjustments, was $36 million higher quarter over quarter, driven by favourable working capital changes at FortisBC and favourable changes in the AESO charges deferral account at FortisAlberta period over period. Cash flow from operating activities, after working capital adjustments, was $115 million higher year to date compared to the same period last year. The increase was driven by favourable changes in the AESO charges deferral account and higher earnings at FortisAlberta combined with favourable working capital changes at the Terasen Gas companies period over period.
Investing Activities: Cash used in investing activities was $22 million higher quarter over quarter, driven by higher gross capital expenditures and lower contributions in aid of construction at FortisAlberta. Cash used in investing activities was $153 million higher year to date compared to the same period last year. During the first quarter of 2008, TGI received approximately $14 million in proceeds associated with the sale of surplus land. Excluding the impact of the sale of surplus land in 2008, cash used in investing activities was $139 million higher year to date compared to the same period last year, driven by higher gross capital expenditures and lower contributions in aid of construction at FortisAlberta.
Gross capital expenditures were $267 million for the third quarter of 2009, $17 million higher than for the same quarter last year, and $763 million year to date, $117 million higher than for the same period last year. The increases were driven by higher utility capital asset spending at FortisAlberta and the Terasen Gas companies.
Financing Activities: Cash provided by financing activities was $52 million lower quarter over quarter. Higher proceeds from long-term debt were more than offset by higher net repayments under committed credit facilities and higher repayments of long-term debt.
Cash provided by financing activities was $71 million higher year to date compared to the same period last year, mainly due to lower net repayments under committed credit facilities and lower repayments of long-term debt, partially offset by higher net repayments of short-term borrowings, lower proceeds from long-term debt and lower proceeds from preference share issues.
Net advances from short-term borrowings were $168 million for the third quarter of 2009, comparable to the same quarter last year. Net repayments of short-term borrowings were $71 million year to date or $35 million higher than for the same period last year. The increase was driven by the Terasen Gas companies, partially offset by lower net repayments of short-term borrowings by Maritime Electric.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease obligations and net borrowings (repayments) under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.
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Fortis Inc.
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Terasen Gas companies - - - 99(1) 496(2)(3) (397)
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FortisAlberta - - - 99(4) 99(5) -
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FortisBC - - - 104(6) - 104
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Newfoundland Power - - - 65(7) - 65
-------------------------------------------------------------------------
Maritime Electric - - - - 60(8) (60)
-------------------------------------------------------------------------
Caribbean Utilities 11(9) - 11 45(9) - 45
-------------------------------------------------------------------------
Corporate 198(10) - 198 198(10) - 198
-------------------------------------------------------------------------
Other - - - - 4 (4)
-------------------------------------------------------------------------
Total 209 - 209 610 659 (49)
-------------------------------------------------------------------------
(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 of 10.75% unsecured debentures that
matured in June 2009.
(2) Issued May 2008, 30-year $250 million 5.80% unsecured debentures by
TGI. The net proceeds were primarily used to repay maturing $188
million 6.20% debentures and short-term borrowings.
(3) Issued February 2008, 30-year $250 million 6.05% unsecured debentures
by TGVI. The net proceeds were used to repay committed credit
facility borrowings.
(4) 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.
(5) Issued April 2008, 30-year $100 million 5.85% unsecured debentures.
The net proceeds were used to repay committed credit facility
borrowings.
(6) Issued June 2009, 30-year $105 million 6.10% unsecured debentures.
The net proceeds were used to repay committed credit facility
borrowings, for general corporate purposes, including financing
capital expenditures and working capital requirements, and help repay
$50 million of 6.75% debentures that matured on July 31, 2009.
(7) Issued May 2009, 30-year $65 million 6.606% first mortgage sinking
fund bonds. The net proceeds were used to repay committed credit
facility borrowings and for general corporate purposes, including
financing capital expenditures.
(8) Issued April 2008, 30-year $60 million 6.05% secured first mortgage
bonds. The proceeds were used to repay short-term borrowings.
(9) Issued May 2009 and July 2009, 15-year US$30 million and US$10
million, respectively, 7.50% unsecured notes. The net proceeds were
used to repay short-term borrowings and finance capital expenditures.
(10) Issued July 2009, 30-year $200 million 6.51% unsecured debentures.
The net proceeds were used to repay in full the indebtedness
outstanding under the Corporation's committed credit facility and for
general corporate purposes.
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Fortis Inc.
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Terasen Gas companies - - - (63) (194) 131
--------------------------------------------------------------------------
FortisBC (51) - (51) (51) - (51)
--------------------------------------------------------------------------
Caribbean Utilities - (11) 11 (16) (11) (5)
--------------------------------------------------------------------------
Fortis Properties (6) (3) (3) (11) (9) (2)
--------------------------------------------------------------------------
Other - (1) 1 (7) (6) (1)
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Total (57) (15) (42) (148) (220) 72
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Fortis Inc.
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended September 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Terasen Gas companies - - - - (261) 261
--------------------------------------------------------------------------
FortisAlberta 36 47 (11) 37 45 (8)
--------------------------------------------------------------------------
FortisBC 2 2 - (29) 10 (39)
--------------------------------------------------------------------------
Newfoundland Power (5) 8 (13) (32) (6) (26)
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Corporate (144) 46 (190) (30) (162) 132
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Total (111) 103 (214) (54) (374) 320
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--------------------------------------------------------------------------
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt issues are used to repay borrowings under the Corporation's committed credit facility. During the third quarter, a net repayment of $144 million under the Corporation's committed credit facility was financed with partial proceeds from the issuance of $200 million unsecured debentures ($198 million net of costs). During the second quarter of 2008, a net repayment of $170 million under the Corporation's committed credit facility was financed with partial proceeds from the issuance of $230 million preference shares ($223 million net of costs).
Proceeds from the issuance of common shares increased $3 million quarter over quarter and $16 million year to date compared to the same period last year, reflecting the impact, effective March 1, 2009, of the Corporation's Amended and Restated Dividend Reinvestment and Share Purchase Plan (the "Dividend Reinvestment and Share Purchase Plan"). The Dividend Reinvestment and Share Purchase 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 $45 million for the third quarter of 2009, up $6 million from the same quarter last year and were $133 million year to date, up $15 million from the same period last year. The increases were primarily due to an increase in the number of common shares outstanding, primarily as a result of the public issuance of 11.7 million common shares in December 2008 and a higher dividend declared per common share compared to the same periods last year. The dividend declared per common share in each of the first, second and third quarters of 2009 was $0.26, while the dividend declared per common share in each of the respective quarters of 2008 was $0.25.
Preference share dividends were comparable quarter over quarter and increased $5 million year to date compared to the same period last year, as a result of the dividends associated with the 9.2 million First Preference Shares, Series G that were issued during the second quarter of 2008.
Contractual Obligations: Consolidated contractual obligations of Fortis for periods over the next five years and thereafter, as of September 30, 2009, are outlined in the following table. A detailed description of the nature of the obligations is provided below and in the MD&A for the year ended December 31, 2008.
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Fortis Inc.
Contractual Obligations (Unaudited)
As at September 30, 2009
--------------------------------------------------------------------------
Total Due Due in Due in Due in
within years 2 years 4 after 5
($ millions) 1 year and 3 and 5 years
--------------------------------------------------------------------------
Long-term debt 5,376 127 368 288 4,593
--------------------------------------------------------------------------
Brilliant Terminal Station 61 3 5 5 48
--------------------------------------------------------------------------
Gas purchase contract
obligations (1) 991 577 215 191 8
--------------------------------------------------------------------------
Power purchase obligations
FortisBC 2,800 38 78 75 2,609
FortisOntario 520 43 95 99 283
Maritime Electric (2) 80 51 12 2 15
Belize Electricity (3) 264 14 35 40 175
--------------------------------------------------------------------------
Capital cost 388 16 39 41 292
--------------------------------------------------------------------------
Joint-use asset and shared
service agreements 62 4 6 6 46
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Office lease - FortisBC 18 1 3 3 11
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Operating lease obligations 152 17 31 28 76
--------------------------------------------------------------------------
Equipment purchase
commitment - Fortis
Turks and Caicos (4) 13 8 5 - -
--------------------------------------------------------------------------
Other 20 5 9 5 1
--------------------------------------------------------------------------
Total 10,745 904 901 783 8,157
--------------------------------------------------------------------------
(1) Based on index prices as at September 30, 2009
(2) Reflects the impact of the extension to December 2010 of the take-or-
pay contract with New Brunswick Power ("NB Power") that previously
expired on March 31, 2009. The contract includes replacement energy
and capacity for the NB Power Point Lepreau Nuclear Generating Station
during its refurbishment outage.
(3) Includes a new 15-year power purchase agreement with Belize Aquaculture
Limited ("BAL"). The agreement provides for the supply of up to 15 MW
of capacity by BAL and expires in April 2024.
(4) Fortis Turks and Caicos has entered into an agreement with a supplier
to purchase two diesel-generating engines with a combined capacity of
approximately 17.5 MW for approximately US$12 million (CDN$13 million)
for delivery in April 2010 and January 2011.
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 2008 and TGVI made an $8 million repayment during the second
quarter of 2009. As at September 30, 2009, the outstanding balance of the
repayable government loans was approximately $53 million. Repayments of
the government loans beyond 2009 are not included in the contractual
obligations table above as the amount and timing of the repayments are
dependent upon annual BCUC approval of the recovery of TGVI's revenue
deficiency deferral account and the ability of TGVI to replace the
government loans with non-government subordinated debt financing on
reasonable commercial terms.
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-fired generating plant. The contract is for three years terminating
in April 2010. The remaining approximate quantities, in millions of
imperial gallons, per the contract, on an annual basis by fiscal year are
27 in 2009 and 9 in 2010. The contract contains an automatic renewal
clause for the years 2010 through to 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.
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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Based on the latest completed actuarial valuations, the Corporation's consolidated defined benefit pension plan funding contributions, including current service, solvency and special funding amounts, are expected to total approximately $22 million for 2009, $18 million for 2010, $6 million for 2011, $3 million for 2012 and $2 million for 2013. These pension funding amounts include additional obligations determined under December 31, 2008 actuarial valuations, completed in the first quarter of 2009, associated with defined benefit pension plans at Newfoundland Power and the Corporation, and under a December 31, 2007 actuarial valuation of a defined benefit pension plan at Terasen, also completed in the first quarter of 2009.
Pension funding obligations for 2010 and beyond may increase pending completion of the next actuarial valuations required as at December 31, 2009 and December 31, 2010 related to the defined benefit pension plans of the larger subsidiaries.
Capital Structure: The Corporation's principal businesses of regulated gas and electricity distribution require ongoing access to capital to allow the utilities to fund the maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level in support of infrastructure investment to ensure regulatory transparency, tax efficiency and financing flexibility. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 40 per cent equity, including preference shares, and 60 per cent debt, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in the utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
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Fortis Inc.
Capital Structure (Unaudited)
As at
--------------------------------------------------------------------------
September 30, 2009 December 31, 2008
--------------------------------------------------------------------------
($ millions) (%) ($ millions) (%)
--------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,604 59.8 5,468 59.5
--------------------------------------------------------------------------
Preference shares (2) 667 7.1 667 7.3
--------------------------------------------------------------------------
Common shareholders' equity 3,100 33.1 3,046 33.2
--------------------------------------------------------------------------
Total 9,371 100.0 9,181 100.0
--------------------------------------------------------------------------
(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
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The slight change in the capital structure was driven by higher debt levels primarily in support of infrastructure investment, increased accumulated other comprehensive loss driven by unfavourable foreign exchange, partially offset by year-to-date net earnings applicable to common shares, net of common share dividends, of $48 million and increased common shares outstanding reflecting the impact of the Corporation's enhanced Dividend Reinvestment and Share Purchase Plan.
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt
credit rating)
DBRS BBB(high) (unsecured debt credit rating)
In September 2009, S&P confirmed its credit rating for Fortis at A- (stable outlook). The credit ratings of Fortis 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.
Year-to-date 2009, gross consolidated capital expenditures were $763 million. A breakdown of gross capital expenditures by segment for year-to-date 2009 is provided in the following table.
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Fortis Inc.
Gross Capital Expenditures (Unaudited) (1)
Year-to-date September 30, 2009
($ millions)
---------------------------------------------------------------------------
Other
Regula- Total
Tera- ted Regula- Regula-
sen New- Utili- ted ted Non-
Gas Fortis found- ties Utili- Utili- Regula-
Compa- Alberta Fortis- land Cana- ties - ties ted- Fortis
nies (2) BC Power dian Cana- Carib- Utility Proper-
(2) (3) (2) (2) (2) dian bean (4) ties Total
---------------------------------------------------------------------------
176 315 79 52 33 655 77 15 16 763
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(1) Relates to utility capital assets, income producing properties and
intangible assets and includes expenditures associated with assets
under construction
(2) Includes asset removal and site restoration expenditures, net of
salvage proceeds, which are permissible in rate base
(3) Includes payments made to the AESO for investment in transmission
capital projects
(4) Includes non-regulated generation, non-regulated gas utility and
Corporate capital expenditures
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Gross consolidated capital expenditures for 2009 are expected to be more than $1 billion, approximately $50 million higher than that disclosed in the MD&A for the year ended December 31, 2008. Planned capital expenditures are based on detailed forecasts of energy demand, weather and cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. The expected increase is driven by FortisAlberta associated with higher anticipated customer driven capital expenditures, including new customer connections, and the inclusion of AESO transmission capital expenditures in total capital expenditures. The increase is partially offset by lower spending at FortisBC associated with the Okanagan Transmission Reinforcement Project, as discussed below, and the timing of other capital projects, combined with lower-than-forecasted capital spending at non-regulated Terasen Energy Services Inc.
Changes in the overall expected level, nature and timing of major capital projects from those disclosed in the MD&A for the year ended December 31, 2008 are discussed below.
FortisAlberta has revised its forecasted capital expenditures related to the replacement of conventional meters with new Automated Meter Infrastructure ("AMI") technology. In response to the direction of the Alberta Department of Energy on AMI capabilities, FortisAlberta has adjusted the scope of its planned AMI program, which has contributed to an increase in the expected overall cost of the project to $168 million from $124 million as disclosed in the MD&A for the year ended December 31, 2008.
TGVI's construction of the 50-kilometer Squamish-to-Whistler natural gas pipeline lateral was completed during spring 2009 with conversion of customer appliances completed in August 2009. The total costs of the construction of the pipeline and conversion of the appliances were approximately $8 million above the amounts previously approved for recovery by the BCUC. Applications will be filed to request inclusion of these costs in rate base.
In June 2009, TGI applied to the BCUC to change its customer care delivery model from an outsourced arrangement to an in-house customer care department, including company-owned call centres and billing operations and a new customer information system. If approved, the new model would be in place effective January 2012 at a total expected capital cost of approximately $120 million including amounts to regulatory deferral accounts, compared to $145 million as previously estimated and disclosed in the second quarter of 2009.
FortisBC began construction on the approximate $110 million Okanagan Transmission Reinforcement Project in August 2009 with completion expected in 2011. The total forecast cost of the project is down from the original estimate of $141 million as disclosed in the MD&A for the year ended December 31, 2008. The decrease in cost is mainly due to lower forecasted labour, equipment and commodity costs. The project relates to upgrading the existing overhead transmission lines from 161 kilovolts ("kV") to 230 kV between Penticton and Oliver and building a new 230-kV terminal in the Oliver area.
Over the five-year period 2009 through 2013, consolidated gross capital expenditures are expected to total approximately $5 billion. Approximately 70 per cent of the capital spending is expected to be incurred at the Regulated Electric Utilities, driven by FortisAlberta, FortisBC and the Corporation's regulated utility operations in the Caribbean. Approximately 25 per cent is expected to be incurred at the Regulated Gas Utilities and the remaining 5 per cent is expected to relate to non-regulated activities. 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.
Management expects consolidated long-term debt maturities and repayments to average approximately $157 million annually over the next five years. The combination of available credit facilities and low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
Fortis and its subsidiaries, except for Belize Electricity and the Exploits Partnership, as described below, were in compliance with debt covenants as at September 30, 2009 and are expected to remain compliant throughout the remainder of 2009.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application, Belize Electricity does not meet certain debt covenant financial ratios related to loans totalling $7 million (BZ$13 million), as at September 30, 2009, with the International Bank for Reconstruction and Development and the Caribbean Development Bank. The Company has informed the lenders of the defaults.
As the hydroelectric assets and water rights of the Exploits Partnership had been provided as security for the Exploits Partnership's 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 loan is without recourse to Fortis and was approximately $60 million as at September 30, 2009. The lenders of the term loan have not demanded accelerated repayment. For further information, see the "Critical Accounting Estimates - Contingencies" section of this MD&A.
As at September 30, 2009, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which approximately $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. Approximately $2.0 billion of the total credit facilities are committed facilities, the majority of which have maturities between 2011 and 2013.
The following table summarizes the credit facilities of the Corporation and its subsidiaries.
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Fortis Inc.
Credit Facilities (Unaudited)
--------------------------------------------------------------------------
Total as at Total as at
($ millions) Corporate Regulated Fortis September September
and Other Utilities Properties 30, 2009 30, 2008
--------------------------------------------------------------------------
Total credit
facilities 645 1,496 13 2,154 2,228
--------------------------------------------------------------------------
Credit facilities
utilized:
--------------------------------------------------------------------------
Short-term
borrowings - (335) (1) (336) (410)
--------------------------------------------------------------------------
Long-term debt - (160) - (160) (224)
--------------------------------------------------------------------------
Letters of credit
outstanding (1) (98) (1) (100) (104)
--------------------------------------------------------------------------
Credit facilities
available 644 903 11 1,558 1,490
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--------------------------------------------------------------------------
As at September 30, 2009 and December 31, 2008, certain borrowings under the Corporation's and/or subsidiaries' credit facilities have been 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.
Corporate and Other
In May 2009, Terasen entered into a $30 million committed revolving credit facility maturing in May 2011 to replace its $100 million committed revolving credit facility that matured in May 2009. The terms of the new credit facility are substantially the same as those of the credit facility it replaced.
Regulated Utilities
On April 30, 2009, FortisBC amended its $150 million unsecured committed revolving credit facility, including extending the maturity date of the $50 million portion of the facility to May 2012 from May 2011 and extending the maturity date of the $100 million portion of the facility to May 2010 from May 2009.
In March 2009, Maritime Electric renegotiated its $50 million demand credit facility and had it converted into a 364-day revolving committed credit facility.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments. The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt and preference shares were as follows.
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Fortis Inc.
Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at September 30, 2009 As at December 31, 2008
--------------------------------------------------------------------------
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Long-term debt, including
current portion (1) 5,376 5,803 5,122 5,040
--------------------------------------------------------------------------
Preference shares,
classified as debt (2) 320 348 320 329
--------------------------------------------------------------------------
(1) Carrying value as at September 30, 2009 excludes unamortized deferred
financing costs of $39 million (December 31, 2008 - $34 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 $347 million preference shares classified as equity was
$343 million as at September 30, 2009 (December 31, 2008: carrying
value $347 million; fair value $268 million).
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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, BECOL, and Fortis Turks and Caicos is the US dollar. The Belizean dollar is pegged to the US dollar at BZ$2.00 equals US$1.00. As at September 30, 2009, the Corporation's corporately held US$390 million 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 September 30, 2009, the Corporation had approximately US$169 million in foreign net investments remaining to be hedged.
The Corporation and its subsidiaries also hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation and its subsidiaries do not hold or issue derivative financial instruments for trading purposes.
The following table summarizes the valuation of the Corporation's consolidated derivative financial instruments.
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Fortis Inc.
Derivative Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at September 30, 2009 As at December 31, 2008
--------------------------------------------------------------------------
Estimated Estimated
Term to Number Carrying Fair Carrying Fair
Asset maturity of Value ($ Value ($ Value ($ Value ($
(Liability) (years) Contracts millions) millions) millions) millions)
--------------------------------------------------------------------------
Interest rate
swap 1 1 - - - -
--------------------------------------------------------------------------
Foreign
exchange
forward
contract Approx. 2 1 1 1 7 7
--------------------------------------------------------------------------
Natural gas
Derivatives:
--------------------------------------------------------------------------
Swaps and
options Up to 5 254 (129) (129) (84) (84)
--------------------------------------------------------------------------
Gas purchase
Contract
premiums Up to 2 98 3 3 (8) (8)
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--------------------------------------------------------------------------
The interest rate swap held by Fortis Properties 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 the change in the fair value of the interest rate swap at Fortis Properties is recorded in other comprehensive income.
The foreign exchange forward contract is held by TGVI and is designated as a hedge of the cash flow risk related to approximately US$25 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 contract 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 value of the foreign exchange forward contract was recorded in accounts receivable as at September 30, 2009 and as at December 31, 2008. The fair value of the natural gas derivatives of $126 million was recorded in accounts payable as at September 30, 2009 (December 31, 2008 - accounts payable $92 million).
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 contract is 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 values of the foreign exchange forward contract and the 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 date.
The fair value of the Corporation's financial instruments, including derivatives, reflects a point-in-time estimate 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 earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
As at September 30, 2009, 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, 2008. There were no changes in the Corporation's significant business risks during the nine months ended September 30, 2009 from those disclosed in the MD&A for the year ended December 31, 2008, except for those described below.
Labour Relations: The two collective agreements governing Newfoundland Power's unionized employees represented by the International Brotherhood of Electrical Workers, Local 1620, were ratified by the union in February and April 2009. The collective agreements are effective October 1, 2008 and expire on September 30, 2011.
Transition to International Financial Reporting Standards ("IFRS"): In July 2009, the International Accounting Standards Board ("IASB") issued the Exposure Draft - Rate-Regulated Activities stating that regulatory assets and liabilities arising from activities subject to cost-of-service regulation can be recognized under IFRS when certain conditions are met. The ability to record regulatory assets and liabilities, as proposed, should reduce earnings' volatility at the Corporation's regulated utilities that may have otherwise resulted under IFRS in the absence of an accounting standard for rate-regulated activities. For further information, refer to the "Future Accounting Changes - Transition to IFRS" section of this MD&A.
Impacts of Global Economic Downturn
The significant impacts of the global economic downturn on the Corporation are provided below. The impacts are comparable with those disclosed in the MD&A for the year ended December 31, 2008.
Capital Expenditures: Gross consolidated capital expenditures are expected to be more than $1 billion for 2009 and total approximately $5 billion over the five-year period from 2009 to 2013. Planned capital expenditures are based on detailed forecasts of energy demand, weather and cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. Significantly reduced energy demand in the Corporation's service territories, as a result of a severe and prolonged downturn in economic conditions, could reduce capital spending which would, in turn, impact rate base and earnings' growth.
Cash Flows: The Corporation does not expect any significant decrease in consolidated annual operating cash flows for 2009, as a result of the continued downturn in the global economy in 2009. The subsidiaries expect to be able to source the cash required to fund their 2009 capital expenditure programs.
Cost of and Access to Capital: The volatility in the global financial and capital markets may increase the cost of, and affect the timing of issuance of, long-term capital by the Corporation and its utilities in 2009. While the cost of borrowing may increase, the Corporation and its utilities expect to continue to have reasonable access to capital in the near to medium terms. Year to date, Fortis and its Canadian regulated utilities raised $695 million in 30-year debt at rates ranging from 5.37% to 7.06% and Caribbean Utilities raised 15-year US$40 million debt at 7.50%. The rates obtained on new long-term debt issued by the Corporation's utilities during the first half of 2009 were, on average, approximately 100 to 150 basis points higher than those that would have been obtained during the same period in 2008. The cost of renewed and extended credit facilities may also increase going forward; however, any increased interest expense and/or fees are not expected to have a material financial impact on the Corporation and its utilities in 2009, as the majority of the total committed credit facilities have maturities between 2011 and 2013. Due to the regulated nature of the Corporation's utilities, increased borrowing costs are eligible to be recovered in future customer rates.
Regulated Allowed Returns: The ROE adjustment mechanisms tied to long-term Canada bond yields utilized at the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power have resulted in lower allowed ROEs. The Terasen Gas companies filed an application with the BCUC requesting a review of the current generic allowed ROE adjustment mechanism and the deemed equity component of the capital structure for TGI. The application contemplates an increase in TGI's allowed ROE to 11 per cent from 8.47 per cent, effective July 1, 2009, and an increase in the allowed common equity component of TGI's capital structure to 40 per cent from 35 per cent, effective January 1, 2010. No change was requested in the risk-premium spread of 70 basis points over TGI's allowed ROE in determining TGVI's allowed ROE. In May 2009, Newfoundland Power requested an increase in its allowed ROE from 8.95 per cent to 11 per cent, in conjunction with its 2010 General Rate Application, to reflect an increase in its cost of capital. Other Canadian regulators are also starting to review cost of capital and related ROE adjustment mechanisms in light of current financial market conditions. FortisAlberta is currently engaged in a Generic Cost of Capital Proceeding with its regulator, which is reviewing 2009 ROE calculations and capital structure levels for gas, electric and pipeline utilities in Alberta that are regulated by the AUC. The National Energy Board ("NEB"), an independent federal agency that regulates several parts of Canada's energy industry, has recently undertaken a review of cost of capital and ROE levels. The NEB recently issued a decision increasing the regulated total cost of capital of Trans Quebec & Maritimes Inc. ("TQM"), a Canadian regulated natural gas pipeline utility, which effectively established about an approximate 100 basis points increase in TQM's allowed ROE for 2008 to 9.7 per cent on a 40 per cent equity ratio. The increase in the total cost of capital and allowed ROE was the result of a change in methodology which now takes into account financial market information which considers, among other things, changes that have impacted financial markets and economic conditions. In October 2009, the NEB also issued a decision stating that its 1994 multi-pipeline return on equity formula, used to determine the cost of capital for regulated pipeline companies, is no longer in effect, as there is doubt as to the on-going correctness of using this formula. Instead, cost of capital will be determined by negotiations between the pipelines and their shippers or by the NEB. In September and October 2009, the OEB held a stakeholder conference reviewing the cost of capital policy for future years as it relates to utilities it regulates in Ontario. The OEB anticipates that any policy changes made as a result of the review process will apply to the setting of rates for the 2010 rate year.
Results of Operations: Achieving organic revenue and earnings' growth at Fortis Properties' Hospitality Division is proving challenging in 2009 as a result of the continued downturn in the global economy and its impact on leisure and business travel and hotel stays. In the Caribbean, the level of, and fluctuations in, tourism and related activities, which are closely tied to economic conditions, influences electricity sales as it impacts electricity demand of the large hotels and condominium complexes that are serviced by the Corporation's regulated utilities in that region. As a result, electricity sales growth at Regulated Caribbean Electric Utilities in 2009 is anticipated to be near zero, down from expected electricity sales growth of 2 per cent as disclosed in the MD&A for the second quarter of 2009, and down from 4 per cent as disclosed in the MD&A for the year ended December 31, 2008. Electricity sales growth was approximately 6 per cent for 2008.
Higher energy prices can result in reduced consumption by residential customers. Natural gas and crude oil exploration and production activities in certain of the Corporation's service territories are closely correlated with natural gas and crude oil prices. The level of these activities can influence energy demand, affecting local energy sales in some of the Corporation's service territories.
Defined Benefit Pension Plans: The fair value of the Corporation's consolidated defined benefit pension plan assets decreased approximately 14 per cent during 2008, mainly due to unfavourable market conditions. As at September 30, 2009, the fair value of the consolidated pension plan assets increased 11 per cent from December 31, 2008. Market-driven changes impacting the performance of pension plan assets and the discount rates may result in material changes in future pension funding requirements and pension expense. The decline in fair value of the pension plan assets during 2008 may have the impact of increasing the Corporation's consolidated defined benefit pension plan funding obligations. The full impact of the decrease in the fair value of the pension plan assets on future funding obligations is not determinable until completion of the next actuarial valuations. With the exception of the defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen, the next scheduled actuarial valuations for funding purposes for defined benefit pension plans of the larger subsidiaries are December 31, 2009 and December 31, 2010. Including the impact of actuarial valuations completed during the first quarter of 2009 for defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen, consolidated pension funding contributions, including current service, solvency and special funding amounts, are expected to increase from what was disclosed in the MD&A for the year ended December 31, 2008 by the following amounts: 2009 - $5 million, 2010 - $6 million, 2011 - $6 million, 2012 - $3 million, and 2013 - $2 million. Fortis expects defined benefit pension plan funding requirements to be sourced primarily from a combination of cash generated from operations and amounts available for borrowing under existing credit facilities.
The discount rates used to determine defined benefit pension expense for 2009 have increased compared to rates used to determine defined benefit pension expense for 2008, as a result of the impact of increased credit risk spreads on investment-grade corporate bonds due to volatility in the capital markets. Fortis expects no material increase in its consolidated pension expense for 2009 related to its defined benefit pension plans. The amortization of 2008 losses associated with the pension plan assets is expected to be largely offset by the impact of higher assumed discount rates. Consolidated defined benefit pension plan expense for 2009 is not being materially impacted by the outcome of the actuarial valuations completed for the defined benefit pension plans at Newfoundland Power and the Corporation and one of the defined benefit pension plans at Terasen during the first quarter of 2009.
Any increase in future pension funding requirements and/or pension expense at the regulated utilities is expected to be recovered from, or refunded to, customers in future rates, subject to forecast risk. At the Terasen Gas companies and FortisBC, however, actual pension expense above or below the forecast pension expense approved for recovery in customer rates for the year is subject to deferral account treatment for recovery from, or refund to, customers in future rates, subject to regulatory approval.
Counterparty Risk: 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 significant credit risk on physical off-system sales. The Terasen Gas companies deal with high credit-quality institutions in accordance with established credit approval practices. Due to events in the capital markets over the past year, including significant government intervention in the banking system, the Terasen Gas companies have further limited the financial counterparties they transact with and have reduced available credit to, or taken additional security from, the physical off-system sales counterparties with which they transact. To date, the Terasen Gas companies have not experienced any counterparty defaults and they do not expect any counterparties to fail to meet their obligations; however, the credit quality of counterparties, as events over the past year have indicated, can change rapidly.
An extended decline in economic conditions could also impair the ability of customers to pay for gas and electricity consumed, thereby affecting the aging and collection of the utilities' trade receivables.
Credit Ratings: Fortis and its regulated utilities do not anticipate any material adverse rating actions by the credit rating agencies in the near term. However, the global financial crisis has placed increased scrutiny on rating agencies and rating agency criteria which may result in changes to credit rating practices and policies. Year-to-date 2009, there was no change in the credit ratings for the Corporation and its currently rated subsidiaries except for Newfoundland Power and TGI. In August 2009, Moody's upgraded the credit rating of Newfoundland Power's first mortgage bonds from Baa1 to A2 and of TGI's secured debentures from A2 to A1. Moody's also confirmed its existing credit ratings for unsecured debt at Terasen, TGI, FortisAlberta and FortisBC; S&P confirmed its existing credit ratings for Fortis, Maritime Electric and Caribbean Utilities; and DBRS confirmed its existing credit ratings for FortisBC, Terasen and TGI.
CHANGES IN ACCOUNTING STANDARDS
During the first quarter of 2009, Fortis changed its method of accounting for its investment in the Exploits Partnership to the equity method from the consolidation method, due to the Corporation no longer having control over the cash flows and operations of the Exploits Partnership. Refer to the "Critical Accounting Estimates - Contingencies" section of this MD&A for a further discussion of the Exploits Partnership.
Effective January 1, 2009, the Corporation adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Rate-Regulated Operations: Effective January 1, 2009, the Canadian Accounting Standards Board (the "AcSB") amended: (i) Canadian Institute of Chartered Accountants ("CICA") Handbook Section 1100, Generally Accepted Accounting Principles, removing the temporary exemption providing relief to entities subject to rate regulation from the requirement to apply the Section to the recognition and measurement of assets and liabilities arising from rate regulation; and (ii) Section 3465, Income Taxes to require the recognition of future income tax liabilities and assets, as well as offsetting regulatory assets and liabilities, by entities subject to rate regulation.
Effective January 1, 2009, with the removal of the temporary exemption in Section 1100, the Corporation must now apply Section 1100 to the recognition of assets and liabilities arising from rate regulation. Certain assets and liabilities arising from rate regulation continue to have specific guidance under a primary source of Canadian GAAP that applies only to the particular circumstances described therein, including those arising under Section 1600, Consolidated Financial Statements, Section 3061, Property, Plant and Equipment, Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and Discontinued Operations. The assets and liabilities arising from rate regulation, as described in Note 5 to the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2009 and Note 4 to the Corporation's 2008 annual audited consolidated financial statements, do not have specific guidance under a primary source of Canadian GAAP. Therefore, Section 1100 directs the Corporation to adopt accounting policies that are developed through the exercise of professional judgment and the application of concepts described in Section 1000, Financial Statement Concepts. In developing these accounting policies, the Corporation may consult other sources, including pronouncements issued by bodies authorized to issue accounting standards in other jurisdictions. Therefore, in accordance with Section 1100, the Corporation has determined that all of its regulatory assets and liabilities qualify for recognition under Canadian GAAP and this recognition is consistent with US Financial Accounting Standard Board's Accounting Standard Codification 980, Regulated Operations. Therefore, there was no effect on the Corporation's consolidated financial statements, as at January 1, 2009, due to the removal of the temporary exemption from Section 1100.
Effective January 1, 2009, Fortis retroactively recognized future income tax assets and liabilities and related regulatory liabilities and assets, without prior period restatement, for the amount of future income taxes expected to be refunded to, or recovered from, customers in future gas and electricity rates. Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $491 million and $24 million, respectively; an increase in regulatory assets and regulatory liabilities of $535 million and $59 million, respectively; and a combined $9 million net increase in income taxes payable, deferred credits, other assets, utility capital assets and goodwill associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items. Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates.
Goodwill and Intangible Assets: Effective January 1, 2009, the Corporation retroactively adopted the new CICA Handbook Section 3064, Goodwill and Intangible Assets. This Section, which replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. As at December 31, 2008, the impact of retroactively adopting Section 3064 was a reclassification of $264 million to intangible assets and related decreases of $262 million to utility capital assets, $1 million to income producing properties and $1 million to other assets, due to the reclassification of the net book value of land, transmission and water rights, computer software costs, franchise costs, customer contracts and other costs.
Credit Risk and the Fair Value of Financial Assets and Financial Liabilities: During the first quarter of 2009, the Corporation adopted the new Emerging Issues Committee Abstract 173 ("EIC-173"), Credit Risk and the Fair Value of Financial Assets and Financial Liabilities, which was issued on January 20, 2009. EIC-173 requires that the Corporation's own credit risk and the credit risk of its counterparties be taken into account in determining the fair value of a financial instrument. There was no material effect on the Corporation's interim unaudited consolidated financial statements as a result of adopting EIC-173.
FUTURE ACCOUNTING CHANGES
Transition to IFRS
In February 2008, the AcSB confirmed that the use of IFRS will be required in 2011 for publicly accountable enterprises in Canada. In October 2009, the AcSB issued a third and final Omnibus Exposure Draft confirming that publicly accountable enterprises in Canada will be required to apply 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 opening IFRS balance sheet as at January 1, 2010 and amounts reported by the Corporation for the year ended December 31, 2010.
The Corporation is continuing to assess the financial reporting impacts of adopting IFRS in 2011. While the impact on future financial position and results of operations is not fully determinable or estimable at this time, proposals put forth by the IASB in its July 2009 Exposure Draft - Rate-Regulated Activities, if adopted, should reduce earnings' volatility at the Corporation's regulated utilities that may have otherwise resulted under IFRS, in the absence of an accounting standard for rate-regulated activities.
The Corporation does anticipate 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.
Differences between IFRS and Canadian GAAP, in addition to those referenced further under "Accounting Policy Impacts and Decisions", may continue to be identified based on further detailed analyses by the Corporation, the outcome of a final standard on accounting for rate-regulated activities and other changes in IFRS prior to the Corporation's conversion to IFRS in 2011.
IFRS Conversion Project: The Corporation commenced its IFRS Conversion Project in 2007 and has established a formal project governance structure which includes the audit committee, senior management and project teams from each of the Fortis subsidiaries. Overall project governance, management and support are coordinated by Fortis. An independent external advisor has also been engaged to assist in the IFRS Conversion Project. Project progress reports are provided to the Corporation's Audit Committee on a quarterly basis. The Corporation has also engaged its external auditors, Ernst & Young, LLP, to review accounting policy determinations as they are arrived at and agreed to internally by the Corporation's project team.
The Corporation's IFRS Conversion Project consists of three phases: Scoping and Diagnostics, Analysis and Development, and Implementation and Review.
Phase One: Scoping and Diagnostics, which involved project planning and staffing and identification of differences between current Canadian GAAP and IFRS, was completed in the first half of 2008. The areas of accounting difference of highest potential impact to the Corporation, based on existing IFRS at the time, were identified to include rate-regulated accounting; property, plant and equipment; investment property; provisions and contingent liabilities; employee benefits; impairment of assets; income taxes; business combinations; and initial adoption of IFRS under the provisions of IFRS 1, First-Time Adoption of International Financial Reporting Standards ("IFRS 1").
Phase Two: Analysis and Development is nearing completion and involves detailed diagnostics and evaluation of the financial impacts of various options and alternative methodologies provided for under IFRS; identification and design of operational and financial business processes; initial staff training and audit committee orientation; analysis of IFRS 1 optional exemptions and mandatory exceptions to the general requirement for full retrospective application upon transition; summarization of 2011 IFRS disclosure requirements; and development of required solutions to address identified issues.
Phase Three: Implementation and Review has commenced and involves the execution of changes to information systems and business processes; completion of formal authorization processes to approve recommended accounting policy changes; and further training programs across the Corporation's finance and other affected areas, as necessary. It will culminate in the collection of financial information necessary to compile IFRS-compliant financial statements and reconciliations; embedding of IFRS into the Corporation's business processes; and audit committee approval of IFRS-compliant interim and annual financial statements for 2011.
Accounting for Rate-Regulated Activities under IFRS: IFRS does not currently provide specific guidance with respect to accounting for rate-regulated activities. However, in December 2008, the IASB initiated a project on accounting for rate-regulated activities and whether or not rate-regulated entities could or should recognize assets or liabilities as a result of rate regulation imposed by a regulatory body.
On July 23, 2009, the IASB issued the Exposure Draft - Rate-Regulated Activities. Comments on the Exposure Draft are to be submitted for consideration by the IASB by November 20, 2009. Based on the IASB's current project timeline, a final standard is expected to be issued in the second quarter of 2010.
Based on the Exposure Draft as it currently exists, regulatory assets and liabilities arising from activities subject to cost-of-service regulation can 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 have otherwise resulted 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. However, uncertainty as to the final outcome of this Exposure Draft, and the final standard on accounting for rate-regulated activities under IFRS, has resulted in the Corporation being unable to reasonably estimate and conclude on the impact on the Corporation's future financial position and results of operations with respect to differences, if any, in accounting for rate-regulated activities under IFRS versus Canadian GAAP.
Regulators in the jurisdictions in which the Corporation maintains regulated utility operations have initiated, or are engaged in, consultative processes aimed at addressing issues related to the transition to IFRS. These regulators are also working to define regulatory accounting requirements and respective changes that may be required subsequent to January 1, 2011.
During the second quarter of 2009, the AUC issued Rule 026 which provides both a set of guiding principles and positions on the elements of IFRS that will be adopted for rate-making purposes. FortisAlberta and other utilities in Alberta regulated by the AUC collaborated closely with the AUC in the development of Rule 026.
Also during the second quarter of 2009, TGI, along with FortisBC and other regulated companies in British Columbia, drafted a set of IFRS guidelines for use in regulatory applications being submitted by the utilities to the BCUC. During the same period, TGI and TGVI filed applications with the BCUC for the purpose of setting customer rates for 2010 and 2011. As part of these applications, TGI and TGVI have applied for changes in accounting policies that would, subject to review by the external auditors, be compliant with IFRS where possible.
Accounting Policy Impacts and Decisions: The Corporation has completed an initial assessment of the impacts of adopting IFRS based on the standards as they currently exist, and identified the following as having the greatest potential to impact the Corporation's accounting policies, financial reporting and information systems requirements upon conversion to IFRS. Final conclusions cannot be reached at this time with respect to the Corporation's rate-regulated entities pending further certainty as to a final IFRS standard on accounting for rate-regulated activities.
(a) Property Plant and Equipment
IFRS and Canadian GAAP contain the same basic principles of accounting for property, plant and equipment; however, differences in application do exist. For example, capitalization of directly attributable costs in accordance with IAS 16, Property, Plant and Equipment ("IAS 16") may require measurement of an item of property, plant and equipment upon initial recognition to include or exclude certain previously recognized amounts under Canadian GAAP. Specifically, there may be changes in accounting for:
i) the amount of capitalized overheads;
ii) the capitalization of major inspections that were previously expensed under Canadian GAAP;
iii) the capitalization of depreciation for which the future economic benefits of that asset are absorbed in the production of another asset; and
iv) the capitalization of borrowing costs in accordance with IAS 23, Borrowing Costs.
However, the IASB's Exposure Draft - Rate-Regulated Activities proposes that, in the case of qualifying rate-regulated entities, amounts approved by the regulator for inclusion in the cost of self-constructed property, plant and equipment for rate-making purposes shall also be included in the cost of these assets for financial reporting purposes, even if the entity would not otherwise be permitted to include these costs in the cost of its property, plant and equipment based on application of IAS 16.
IAS 16 also requires an allocation of the amount initially recognized in respect of an item of property, plant and equipment to its significant parts and the depreciation of each such part separately. This method of componentizing property, plant and equipment may result in an increase in the number of component parts that are recorded and depreciated and, as a result, may impact the calculation of depreciation expense.
Upon transition to IFRS, an entity has the elective option to reset the cost of its property, plant and equipment based on fair value in accordance with the provisions of IFRS 1, and to use either the cost model or the revaluation model to measure its property, plant and equipment subsequent to transition. Upon transition to IFRS on January 1, 2010, the Corporation currently intends to reset the cost of hotel properties owned by its non-regulated subsidiary, Fortis Properties, based on fair value and to use the cost model to measure all of Fortis Properties' property, plant and equipment (excluding those assets to be reclassified as investment property under IFRS, as discussed below under "Investment Property") subsequent to transition.
The Exposure Draft - Rate-Regulated Activities proposes a new transitional exemption for qualifying rate-regulated entities that will allow them to use, as of the date of transition, the carrying amount of property, plant and equipment under Canadian GAAP as the deemed cost under IFRS. The Corporation's rate-regulated utility subsidiaries will likely avail of this exemption, should the Exposure Draft be adopted as proposed.
The final extent of the impact of applying IAS 16 by the Corporation's rate-regulated utility subsidiaries, and elective options with respect to accounting for their property, plant and equipment upon transition to IFRS, cannot be made at this time pending further certainty as to a final standard on accounting for rate-regulated activities.
(b) Investment Property
IAS 40, Investment Property ("IAS 40") defines investment property as land or buildings held to earn rental income, for capital appreciation or both. The Corporation's real estate assets, which are currently owned by its non-regulated subsidiary, Fortis Properties, and recorded as property, plant and equipment under Canadian GAAP, will be re-classified as investment property under IFRS.
The Corporation has the elective option to reset the cost of investment property based on fair value at the date of transition. IAS 40 provides further options for measuring investment property subsequent to initial recognition using either the cost model or the fair value model. Currently, Fortis Properties intends to reset the cost of its investment property upon transition to IFRS based on fair value as of January 1, 2010 and to use the fair value model to measure its investment property subsequent to transition. Use of the fair value model under IAS 40 means that the Corporation will not recognize depreciation expense on its statement of earnings under IFRS with respect to its investment properties and changes in the fair value of its investment properties will be recognized in earnings each period.
(C) Provisions and Contingent Liabilities
IAS 37, Provisions, Contingent Liabilities and Contingent Assets ("IAS 37") requires a provision to be recognized when: (i) there is a present obligation as a result of a past transaction or event; (ii) it is probable that an outflow of resources will be required to settle the obligation; and (iii) a reliable estimate can be made of the obligation. The threshold for recognition of a provision under Canadian GAAP is higher than under IFRS. It is possible, therefore, that some contingent liabilities which would not have been recognized under Canadian GAAP may meet the criteria for recognition as a provision under IFRS.
(d) Employee Benefits
IAS 19, Employee Benefits ("IAS 19") requires past service costs associated with defined benefit plans to be expensed on an accelerated basis with vested past service costs to be expensed immediately and unvested past service costs to be expensed on a straight-line basis until the benefits become vested. In addition, actuarial gains and losses are permitted to be recognized directly in equity rather than through earnings, and IFRS 1 also provides an option to recognize immediately in retained earnings all cumulative actuarial gains and losses existing as at the date of transition to IFRS.
Under Canadian GAAP, past service costs are generally amortized on a straight-line basis over the expected average remaining service period of active employees in the defined benefit plan.
The Corporation and its subsidiaries maintain a number of defined benefit pension plans and supplementary and other post-employment benefit plans which will be subject to different accounting treatment under IFRS as compared to Canadian GAAP. The full extent of the impact of applying IAS 19 by the Corporation cannot be made at this time, pending further certainty as to a final standard on accounting for rate-regulated activities.
(e) Impairment of Assets
IAS 36, Impairment of Assets ("IAS 36") uses a one-step approach for testing and measuring asset impairments, with asset carrying values being compared to the higher of value in use and fair value less costs to sell. Value in use is defined as being equal to the present value of future cash flows expected to be derived from the asset in its current state. In the absence of an active market, fair value less costs to sell may also be determined using discounted cash flows. The use of discounted cash flows under IFRS to test and measure asset impairment differs from Canadian GAAP where undiscounted future cash flows are used to compare against the asset's carrying value to determine if impairment exists. This may result in more frequent write-downs in the carrying value of assets under IFRS since asset carrying values that were previously supported under Canadian GAAP based on undiscounted cash flows may not be supported on a discounted cash flow basis under IFRS. However, under IAS 36, previous impairment losses may be reversed where circumstances change such that the impairment has reduced. This also differs from Canadian GAAP, which prohibits the reversal of previously recognized impairment losses.
As the majority of the Corporation's assets are owned by utility subsidiaries that are rate regulated, the potential for and extent of any impairment losses will be primarily subject to the continued ability of the utilities to recover costs through the regulatory process.
As stated above, the Corporation intends to reset the cost of investment property owned by its non-regulated subsidiary, Fortis Properties, upon transition to IFRS based on fair value as of January 1, 2010 and to use the fair value model to measure its investment property subsequent to transition. Changes in the fair value of the Corporation's investment property each period will, therefore, be reflected under IFRS in the statement of earnings.
The Corporation's other non-regulated assets will be subject to the one-step approach under IFRS for testing and measuring asset impairments which may result in some impairments being recognized or reversed under IFRS that would not have been required or permitted under Canadian GAAP.
(f) Income Taxes
IAS 12, Income Taxes ("IAS 12") prescribes that an entity account for the tax consequences of transactions and other events in the same way that it accounts for the transactions and other events themselves. Therefore, where transactions and other events are recognized in earnings, the recognition of deferred tax assets or liabilities which arise from those transactions should also be recorded in earnings. For transactions that are recognized outside of the statement of earnings, either in other comprehensive income or directly in equity, any related tax effects should also be recognized outside of the statement of earnings.
The most significant impact of IAS 12 on the Corporation will be derived directly from the accounting policy decisions made under IAS 16 and IAS 40. In addition, the Corporation's rate-regulated utility subsidiaries currently account for income taxes based on regulatory decisions. Therefore, the impact on the Corporation of accounting for the tax consequences of transactions and other events under IFRS versus Canadian GAAP cannot be fully determined at this time pending further certainty as to a final IFRS standard on accounting for rate-regulated activities.
(g) Business Combinations
Under IFRS 3, Business Combinations ("IFRS 3"), business combinations must be accounted for by applying the acquisition method. One of the parties to a business combination can always be identified as the acquirer, being the entity that obtains control of the other business. Control is defined as the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. Fortis, as an acquirer, shall identify the date on which it obtains control of an acquiree. This date is usually the closing date of the acquisition, which would generally be the date on which the Corporation legally transfers the consideration or acquires the assets and assumes the liabilities of the acquiree. As of the date on which it obtains control, Fortis shall recognize, separately from goodwill, the identifiable assets acquired, the liabilities assumed and any non-controlling interest in the acquiree in accordance with IFRS 3.
In accordance with IFRS 3, acquisition-related costs incurred to effect a business combination shall be expensed in the period the costs are incurred. Under IFRS, these costs are not permitted to form a component of goodwill as is permitted under Canadian GAAP.
Under IFRS 1, an entity has the option to retroactively apply IFRS 3 to all business combinations or may elect to apply the standard prospectively only to those business combinations that occur after the date of transition. The Corporation currently intends to avail of the elective exemption under IFRS 1 which removes the requirement to retrospectively restate all business combinations prior to the date of transition to IFRS, subject to certain balance sheet adjustments that may be required at FortisAlberta with respect to goodwill and intangible assets that have been recorded previously under Canadian GAAP using pushdown accounting. These adjustments are not expected to have an impact on the Corporation's consolidated financial position upon transition to IFRS.
The AcSB recently issued new CICA Handbook Section 1582, Business Combinations and Section 1602, Non-Controlling Interests. The effective date of these sections is fiscal years beginning on or after January 1, 2011, however, early adoption is permitted. These new Handbook sections are substantially aligned with the accounting for business combinations and non-controlling interests under IFRS 3.
(h) IFRS 1, First-Time Adoption of International Financial Reporting Standards
IFRS 1 provides the framework for the first time adoption of IFRS and specifies that, in general, an entity shall apply the principles under IFRS retrospectively. IFRS 1 also specifies that the adjustments that arise on retrospective conversion to IFRS from other GAAP should be recognized directly in retained earnings. Certain optional exemptions and mandatory exceptions to retrospective application are provided for under IFRS 1.
The Corporation has completed an analysis of IFRS 1. While preliminary decisions have been made with respect to the elective exemptions available upon transition, final decisions cannot be made at this time pending further certainty as to a final IFRS standard on accounting for rate-regulated activities.
(i) Internal Controls over Financial Reporting and Disclosure
In accordance with the Corporation's approach to certification of internal controls required under Canadian Securities Administrators' National Instrument 52-109, all entity level, information technology, disclosure and business process controls will require updating and testing to reflect changes arising from the Corporation's conversion to IFRS. Where material changes are identified, these changes will be mapped and tested to ensure that no material deficiencies exist as a result of the Corporation's conversion to these new accounting standards.
(j) Information Systems
It is anticipated that the adoption of IFRS will have some impact on information systems requirements. The Corporation has assessed the need for systems upgrades or modifications to ensure an efficient conversion to IFRS. As part of Phase Two of the Corporation's IFRS Conversion Project, information systems' plans have been prepared for implementation in Phase Three. The extent of the impact on the Corporation's information systems is largely dependant upon certainty as to a final IFRS standard on accounting for rate-regulated activities.
The IASB has a number of on-going projects on its agenda, in addition to the project on accounting for rate-regulated activities, that may result in changes to existing IFRS prior to the Corporation's conversion to IFRS in 2011. The Corporation continues to monitor these projects and the impact that any resulting IFRS changes may have on its anticipated accounting policies, financial position or results of operations under IFRS for 2011 and beyond.
Business Combinations
In January 2009, the AcSB issued new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-Controlling Interests. These new accounting standards are effective for fiscal years beginning on or after January 1, 2011. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of the acquiree will result in a different calculation of goodwill with respect to future acquisitions. 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. Section 1582 will affect the recognition of business combinations completed by the Corporation on or after January 1, 2011 and, as a result, may have a material impact on the Corporation's consolidated earnings and financial position.
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 will result 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 the non-controlling interests are required to be separately disclosed on the statement of earnings. The adoption of Sections 1601 and 1602 is not expected to have a material impact on the Corporation's consolidated earnings, cash flows or financial position.
Financial Instruments
In June 2009, the AcSB issued amendments to the CICA Handbook Section 3862, Financial Instruments - Disclosures to include additional disclosure requirements about the fair value measurement of financial instruments and to enhance liquidity risk disclosures. The amendments are effective for annual financial statements relating to fiscal years ending after September 30, 2009. The Corporation will reflect the additional disclosures in its 2009 annual audited consolidated financial statements.
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 nine months ended September 30, 2009 from those disclosed in the Corporation's MD&A for the year ended December 31, 2008, except for those described below related to income taxes, goodwill and contingencies.
Income Taxes: Income taxes are determined based on estimates of the Corporation's current income taxes and estimates of future income taxes resulting from temporary differences between the carrying values of assets and liabilities in the consolidated financial statements and their tax values. The use of estimation with respect to recording future income taxes has increased due to the adoption by the Corporation of amended CICA Handbook Section 3465, Income Taxes, effective January 1, 2009. A future income tax asset or liability is determined for each temporary difference based on the future tax rates that are expected to be in effect and management's assumptions regarding the expected timing of the reversal of such temporary differences. Future income tax assets are assessed for the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered more likely than not, a valuation allowance is recorded and charged against earnings in the period that the allowance is created or revised. Estimates of the provision for income taxes, future income tax assets and liabilities, and any related valuation allowance might vary from actual amounts incurred.
Goodwill: Annually, the Corporation tests for impairment of goodwill. During 2009, Fortis changed the date of the annual goodwill impairment test from July 31st to October 1st to better correspond with the timing of the preparation of the Corporation's and subsidiaries' annual financial budgets. Accordingly, this accounting change is preferable in the Corporation's circumstance. The change in timing of the test did not delay, accelerate or avoid any impairment charge. The Corporation performed the annual goodwill impairment test as at July 31, 2009 and determined that no goodwill impairment provision was required. The test is being performed again as at October 1, 2009. The change in the timing of the impairment test had no impact on the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2009.
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 during the nine months ended September 30, 2009 from those disclosed in the MD&A for the year ended December 31, 2008, except as disclosed below.
Exploits Partnership
The Exploits Partnership operated two non-regulated hydroelectric generation plants in Newfoundland with a combined capacity of approximately 140 MW. The Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent by Abitibi. In December 2008, the Government of Newfoundland and Labrador expropriated Abitibi's hydroelectric assets and water rights in Newfoundland, including those of the Exploits Partnership. The newsprint mill in Grand Falls-Windsor closed on February 12, 2009, subsequent to which the day-to-day operations of the Exploits Partnership's hydroelectric generating facilities were assumed by Nalcor Energy, a Crown corporation, as an agent for the Government of Newfoundland and Labrador. The loss of control over cash flows and operations required Fortis to report its investment in the Exploits Partnership using the equity method of accounting, effective February 13, 2009. Equity earnings recognized year-to-date 2009 are equivalent to the amounts that would have been recognized under normal hydrology in the absence of the expropriation. Discussions between Fortis Properties and Nalcor Energy with respect to expropriation matters are ongoing.
Terasen
On July 16, 2009, Terasen was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to a pipeline rupture in July 2007. Terasen has filed a statement of defence but the claim is in its early stages and the amount and outcome of it is indeterminable at this time.
QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended December 31, 2007 through September 30, 2009. 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 2008 annual audited consolidated financial statements. The quarterly operating 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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Fortis Inc.
Summary of Quarterly Results (Unaudited)
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Net Earnings
Applicable
to Common
Revenue Shares Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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September 30, 2009 664 36 0.21 0.21
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June 30, 2009 754 53 0.31 0.31
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March 31, 2009 1,201 92 0.54 0.52
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December 31, 2008 1,182 76 0.48 0.46
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September 30, 2008 727 49 0.31 0.31
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June 30, 2008 848 29 0.19 0.18
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March 31, 2008 1,146 91 0.58 0.55
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December 31, 2007 1,018 79 0.51 0.49
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A summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of gas and electricity demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also impacted by the cost of fuel and purchased power and the commodity cost of natural gas, which are flowed through to customers without mark up. Given the diversified group of 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, on April 30, 2009, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario. Financial results for the second quarter ended June 30, 2008 reflected the $13 million unfavourable impact to Fortis of a charge recorded at Belize Electricity as a result of the June 2008 regulatory rate decision. Due to a shift in the quarterly distribution of annual purchased power expense at Newfoundland Power, the utility's earnings in 2008 were lower in the fourth quarter compared to the same quarter in 2007. Newfoundland Power's annual earnings were not impacted by the shift in the quarterly distribution of annual purchased power expense. Financial results from November 2008 were impacted by the acquisition of the Sheraton Hotel Newfoundland and from April 2009 by the acquisition of the Holiday Inn Select in Windsor, Ontario.
September 30, 2009/September 30, 2008 - Net earnings applicable to common shares 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 that 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 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 generation was primarily associated with the loss of earnings subsequent to the expiration, on April 30, 2009, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario. Lower earnings at Newfoundland Power were largely associated with higher operating expenses and amortization costs.
June 30, 2009/June 30, 2008 - Net earnings applicable to common shares 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 from non-regulated hydroelectric generation primarily associated with the loss of earnings subsequent to the expiration, on April 30, 2009, of the power-for-water exchange agreement related to the Rankine hydroelectric generating facility in Ontario.
March 31, 2009/March 31, 2008 - Net earnings applicable to common shares were $92 million, or $0.54 per common share, for the first quarter of 2009 compared to earnings of $91 million, or $0.58 per common share, for the first quarter of 2008. Results were driven by growth in electrical infrastructure investment and customers at the Regulated Electric Utilities in western Canada, partially offset by lower earnings at the Caribbean Regulated Utilities and Fortis Properties. Excluding one-time gains of approximately $2 million at Fortis Turks and Caicos, earnings at the Caribbean Regulated Utilities were $3 million lower quarter over quarter, resulting from reduced electricity sales attributable to cooler weather and the impact of the global economic downturn on energy demand combined with the lower allowed ROAs at Caribbean Utilities and Belize Electricity. The decrease was partially mitigated by the favourable impact of foreign exchange rates associated with the strengthening US dollar quarter over quarter. Fortis Properties' results were reduced by one-time transitional operating costs associated with the Sheraton Hotel Newfoundland, acquired in November 2008, and the impact of lower hotel occupancies.
December 31, 2008/December 31, 2007 - Net earnings applicable to common shares were $76 million, or $0.48 per common share, for the fourth quarter of 2008 compared to earnings of $79 million, or $0.51 per common share, for the fourth quarter of 2007. Fourth quarter results for 2007 were favourably impacted by one-time items totalling approximately $13 million related to: (i) the sale of surplus land at TGI; (ii) the reduction of future income tax liability balances at Fortis Properties related to lower enacted corporate income tax rates; and (iii) an interconnection agreement-related refund at FortisOntario. Excluding these one-time items, earnings were $10 million higher quarter over quarter. The increase was driven by stronger performance and lower corporate taxes at FortisAlberta, lower corporate expenses and $1 million of additional earnings from Caribbean Utilities related to a change in the utility's fiscal year end. The increase was partially offset by the impact of: (i) a lower allowed ROA at Belize Electricity, effective July 1, 2008; (ii) an approximate $1 million loss of revenue at Fortis Turks and Caicos related to Hurricane Ike; and (iii) an approximate $2 million reduction in fourth quarter earnings at Newfoundland Power associated with a shift in the quarterly distribution of the utility's annual purchased power expense.
SUBSEQUENT EVENTS
In October 2009, FortisOntario acquired Great Lakes Power Distribution Inc., subsequently renamed Algoma Power, for an aggregate purchase price of $75 million, including cash acquired, subject to adjustment. Algoma Power is an electric distribution utility serving approximately 12,000 customers in the district of Algoma in northern Ontario.
In October 2009, FortiaAlberta issued 30-year $125 million 5.37% unsecured debentures, the net proceeds of which will be used to repay committed credit facility borrowings that were incurred primarily to finance capital expenditures, and for general corporate purposes.
OUTLOOK
Gross consolidated capital expenditures are estimated to be more than $1 billion in 2009 and total approximately $5 billion for the five-year period 2009 through 2013. The Corporation's capital program is expected to drive growth in earnings and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing on opportunities to acquire regulated natural gas and electric utilities in the United States and Canada. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at November 4, 2009, the Corporation had issued and outstanding 170.7 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; and 9.2 million First Preference Shares, Series G. 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 Series E were converted as at November 4, 2009 is as follows:
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Fortis Inc.
Conversion of Securities into Common Shares (Unaudited)
As at November 4, 2009
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Security Number of Common Shares (millions)
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Stock Options 4.8
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Convertible Debt 1.4
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First Preference Shares, Series C 5.2
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First Preference Shares, Series E 8.2
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Total 19.6
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Additional information, including the Fortis 2008 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and nine months ended September 30, 2009 and 2008
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30, December 31,
2009 2008
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(Restated
- Note 2)
ASSETS
Current assets
Cash and cash equivalents $106 $66
Accounts receivable 357 681
Prepaid expenses 31 17
Regulatory assets (Note 5) 196 157
Inventories (Note 6) 211 229
Future income taxes (Note 15) 17 -
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918 1,150
Other assets 172 230
Regulatory assets (Note 5) 728 203
Future income taxes (Note 15) 29 54
Utility capital assets 7,500 7,153
Income producing properties 553 540
Intangible assets (Note 7) 264 273
Goodwill (Note 8) 1,563 1,575
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$11,727 $11,178
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 20) $336 $410
Accounts payable and accrued charges 712 874
Dividends payable 47 47
Income taxes payable 10 66
Regulatory liabilities (Note 5) 36 45
Current installments of long-term debt and
capital lease obligations (Note 9) 130 240
Future income taxes (Note 15) 17 15
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1,288 1,697
Deferred credits 308 277
Regulatory liabilities (Note 5) 450 401
Future income taxes (Note 15) 546 61
Long-term debt and capital lease obligations
(Note 9) 5,244 4,884
Non-controlling interest 124 145
Preference shares 320 320
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8,280 7,785
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Shareholders' equity
Common shares (Note 10) 2,482 2,449
Preference shares 347 347
Contributed surplus 10 9
Equity portion of convertible debentures 5 6
Accumulated other comprehensive loss (Note 12) (79) (52)
Retained earnings 682 634
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3,447 3,393
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$11,727 $11,178
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Contingent liabilities and commitments (Note 22)
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2009 2008 2009 2008
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Revenue $664 $727 $2,619 $2,721
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Expenses
Energy supply costs 253 320 1,279 1,427
Operating 182 174 561 535
Amortization 91 86 274 255
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526 580 2,114 2,217
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Operating income 138 147 505 504
Finance charges
(Note 14) 91 89 267 270
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Earnings before
corporate taxes and
non-controlling
interest 47 58 238 234
Corporate taxes
(Note 15) 2 - 34 48
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Net earnings before
non-controlling
interest 45 58 204 186
Non-controlling
interest 4 4 9 8
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Net earnings 41 54 195 178
Preference share
dividends 5 5 14 9
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Net earnings
applicable to
common shares $36 $49 $181 $169
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Earnings per common
share (Note 10)
Basic $0.21 $0.31 $1.06 $1.08
Diluted $0.21 $0.31 $1.05 $1.06
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See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2009 2008 2009 2008
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Balance at beginning
of period $691 $592 $634 $551
Net earnings
applicable to common
shares 36 49 181 169
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727 641 815 720
Dividends on common
shares (45) (39) (133) (118)
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Balance at end of
period $682 $602 $682 $602
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See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2009 2008 2009 2008
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Net earnings $41 $54 $195 $178
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Other comprehensive
income
Unrealized foreign
currency translation
(losses) gains on net
investments in
self-sustaining
foreign operations (51) 22 (79) 35
Gains (losses) on
hedges of net
investments in
self-sustaining
foreign operations 37 (17) 59 (28)
Corporate tax
(expense) recovery (5) 2 (8) 4
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Change in unrealized
foreign currency
translation (losses)
gains, net of hedging
activities and
tax (Note 12) (19) 7 (28) 11
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Gain on derivative
instruments
designated as cash
flow hedges,
net of tax (Note 12) - - 1 -
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Comprehensive
income $22 $61 $168 $189
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See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2009 2008 2009 2008
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(Restated (Restated
- Note 2) - Note 2)
Operating Activities
Net earnings $41 $54 $195 $178
Items not affecting cash
Amortization
- utility capital
assets and income
producing properties 78 74 238 225
Amortization
- intangibles assets 12 10 32 28
Amortization
- other 1 2 4 2
Future income
taxes (Note 15) 2 2 9 17
Non-controlling
interest 4 4 9 8
Write-down of
deferred power
costs - Belize
Electricity - - - 18
Other (2) (2) (9) (6)
Change in long-term
regulatory assets
and liabilities 7 (13) 30 (3)
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143 131 508 467
Change in non-cash
operating working
capital (80) (104) 59 (15)
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63 27 567 452
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Investing Activities
Change in other assets
and deferred credits 1 (6) (4) (9)
Capital expenditures
- utility capital
assets (251) (240) (725) (609)
Capital expenditures
- income producing
properties (4) (3) (15) (11)
Capital expenditures
- intangible assets (12) (7) (23) (26)
Contributions in aid
of construction 14 28 40 60
Proceeds on sale of
utility capital
assets 1 (1) 1 15
Business acquisition
(Note 21) - - (7) -
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(251) (229) (733) (580)
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Financing Activities
Change in short-term
borrowings 168 160 (71) (36)
Proceeds from
long-term debt, net
of issue costs 209 - 610 659
Repayments of
long-term debt and
capital lease
obligations (57) (15) (148) (220)
Net (repayments)
borrowings under
committed credit
facilities (111) 103 (54) (374)
Advances (to) from
non-controlling
interest (5) 4 (5) 4
Issue of common
shares, net of costs 8 5 32 16
Issue of preference
shares, net of costs - - - 223
Dividends
Common shares (45) (39) (133) (118)
Preference shares (5) (5) (14) (9)
Subsidiary dividends
paid to
non-controlling
interest (3) (2) (8) (7)
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159 211 209 138
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Effect of exchange rate
changes on cash and
cash equivalents (2) - (3) -
-------------------------------------------------------------------------
Change in cash and
cash equivalents (31) 9 40 10
Cash and cash
equivalents, beginning
of period 137 59 66 58
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Cash and cash
equivalents, end of
period $106 $68 $106 $68
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Supplementary information to consolidated statements of cash flows (Note
17)
See accompanying Notes to interim consolidated financial statements.
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2009 and 2008
(unless otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international distribution utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated generation assets, and commercial real estate 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 newly converted natural gas distribution system in Whistler, British Columbia, which provides service mainly to residential and commercial customers.
Regulated Electric Utilities - Canadian
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., Cornwall Street Railway, Light and Power Company, Limited and, as of October 2009, Algoma Power Inc. ("Algoma Power") (formally Great Lakes Power Distribution Inc.) (Note 23). 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 Holdings Inc., Rideau St. Lawrence Holdings Inc. and Grimsby Power Inc., three regional electric distribution companies.
Regulated Electric Utilities - Caribbean
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, including an additional 2.7 per cent interest acquired in July 2009. Caribbean Utilities is a public company traded on the Toronto Stock Exchange (TSX:CUP.U). Previously, Caribbean Utilities had an April 30th fiscal year end whereby, up to and including the third quarter of 2008, its financial statements were consolidated in the financial statements of Fortis on a two-month lag basis. In 2008, Caribbean Utilities changed its fiscal year end to December 31st. The change in Caribbean Utilities' fiscal year end eliminates the previous two-month lag in consolidating its financial results.
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 on Turks and Caicos Islands. The Company has a combined diesel-fired generating capacity of 54 MW.
NON-REGULATED - FORTIS GENERATION
a. Belize: Operations consist of the 25-MW Mollejon and 7-MW Chalillo hydroelectric generating facilities in Belize. All of the output of these facilities is sold to Belize Electricity under a 50-year power purchase agreement expiring in 2055. 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 a 5-MW gas-fired cogeneration plant in Cornwall and six small hydroelectric generating stations in eastern Ontario with a combined capacity of 8 MW. Until April 30, 2009, non-regulated operations in Ontario also included 75 MW of water-right entitlement associated with the Niagara Exchange Agreement, which expired on April 30, 2009 in accordance with its terms.
c. Central Newfoundland: Through the Exploits River Hydro Partnership ("Exploits Partnership"), a partnership between the Corporation, through its wholly owned subsidiary Fortis Properties, and AbitibiBowater Inc., formerly Abitibi-Consolidated Company of Canada ("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. The Exploits Partnership sells its output to Newfoundland and Labrador Hydro Corporation under a 30-year power purchase agreement expiring in 2033. Effective February 13, 2009, Fortis commenced accounting for its investment in the Exploits Partnership using the equity method of accounting. Previously, the Corporation consolidated the financial results of the Exploits Partnership in its financial statements (Note 22).
d. British Columbia: Includes the 16-MW run-of-river Walden hydroelectric power plant near Lillooet, British Columbia. This 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 US 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").
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns 21 hotels with more than 4,000 rooms in eight Canadian provinces and approximately 2.8 million square feet of commercial real estate 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 primarily 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 revenues; 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, and 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. While currently not significant, 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 should be read in conjunction with the Corporation's 2008 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 2008 annual audited consolidated financial statements, except as described below.
During the first quarter of 2009, Fortis changed its method of accounting for its investment in the Exploits Partnership to the equity method from the consolidation method, due to the Corporation no longer having control over the cash flows and operations of the Exploits Partnership (Note 22).
Effective January 1, 2009, the Corporation adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Rate-Regulated Operations
Effective January 1, 2009, the Canadian Accounting Standards Board (the "AcSB") amended: (i) CICA Handbook Section 1100, Generally Accepted Accounting Principles, removing the temporary exemption providing relief to entities subject to rate regulation from the requirement to apply the Section to the recognition and measurement of assets and liabilities arising from rate regulation; and (ii) Section 3465, Income Taxes to require the recognition of future income tax liabilities and assets, as well as offsetting regulatory assets and liabilities, by entities subject to rate regulation.
Effective January 1, 2009, with the removal of the temporary exemption in Section 1100, the Corporation must now apply Section 1100 to the recognition of assets and liabilities arising from rate regulation. Certain assets and liabilities arising from rate regulation continue to have specific guidance under a primary source of Canadian GAAP that applies only to the particular circumstances described therein, including those arising under Section 1600, Consolidated Financial Statements, Section 3061, Property, Plant and Equipment, Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and Discontinued Operations. The assets and liabilities arising from rate regulation, as described in Note 5 to these interim consolidated financial statements and Note 4 to the Corporation's 2008 annual audited consolidated financial statements, do not have specific guidance under a primary source of Canadian GAAP. Therefore, Section 1100 directs the Corporation to adopt accounting policies that are developed through the exercise of professional judgment and the application of concepts described in Section 1000, Financial Statement Concepts. In developing these accounting policies, the Corporation may consult other sources, including pronouncements issued by bodies authorized to issue accounting standards in other jurisdictions. Therefore, in accordance with Section 1100, the Corporation has determined that all of its regulatory assets and liabilities qualify for recognition under Canadian GAAP and this recognition is consistent with US Financial Accounting Standard Board's Accounting Standard Codification 980, Regulated Operations. Therefore, there was no effect on the Corporation's consolidated financial statements, as at January 1, 2009, due to the removal of the temporary exemption from Section 1100.
Effective January 1, 2009, Fortis retroactively recognized future income tax assets and liabilities and related regulatory liabilities and assets, without prior period restatement, for the amount of future income taxes expected to be refunded to, or recovered from, customers in future gas and electricity rates. Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $491 million and $24 million, respectively; an increase in regulatory assets and regulatory liabilities of $535 million and $59 million, respectively; and a combined $9 million net increase in income taxes payable, deferred credits, other assets, utility capital assets and goodwill associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items. Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates.
Goodwill and Intangible Assets
Effective January 1, 2009, the Corporation retroactively adopted the new CICA Handbook Section 3064, Goodwill and Intangible Assets. This Section, which replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs, establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. As at December 31, 2008, the impact of retroactively adopting Section 3064 was a reclassification of $264 million to intangible assets and related decreases of $262 million to utility capital assets, $1 million to income producing properties and $1 million to other assets due to the reclassification of the net book value of land, transmission and water rights, computer software costs, franchise costs, customer contracts and other costs.
Credit Risk and the Fair Value of Financial Assets and Financial Liabilities
During the first quarter of 2009, the Corporation adopted the new Emerging Issues Committee Abstract 173 ("EIC-173"), Credit Risk and the Fair Value of Financial Assets and Financial Liabilities, which was issued on January 20, 2009. EIC-173 requires that the Corporation's own credit risk and the credit risk of its counterparties be taken into account in determining the fair value of a financial instrument. There was no material effect on the Corporation's interim consolidated financial statements as a result of adopting EIC-173.
3. FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards ("IFRS")
In February 2008, the AcSB confirmed that the use of IFRS will be required in 2011 for publicly accountable enterprises in Canada. In October 2009, the AcSB issued a third and final Omnibus Exposure Draft confirming that publicly accountable enterprises in Canada will be required to apply 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 opening IFRS balance sheet as at January 1, 2010 and amounts reported by the Corporation for the year ended December 31, 2010. The AcSB proposes that CICA Handbook Section 1506, Accounting Changes, paragraph 30, which would require an entity to disclose information relating to a new primary source of GAAP that has been issued but is not yet effective and that the entity has not applied, not be applied with respect to this Exposure Draft. Fortis is continuing to assess the financial reporting impacts of adopting IFRS.
In July 2009, the IASB issued the Exposure Draft - Rate-Regulated Activities with a final standard expected to be issued in the second quarter of 2010. Based on the Exposure Draft as it currently exists, regulatory assets and liabilities arising from activities subject to cost-of-service regulation can 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 have otherwise resulted 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. However, uncertainty as to the final outcome of this Exposure Draft, and the final standard on accounting for rate-regulated activities under IFRS, has resulted in the Corporation being unable to reasonably estimate and conclude on the impact on the Corporation's future financial position and results of operations with respect to differences, if any, in accounting for rate-regulated activities under IFRS versus Canadian GAAP.
Fortis does anticipate 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.
Business Combinations
In January 2009, the AcSB issued new CICA Handbook Section 1582, Business Combinations, together with Section 1601, Consolidated Financial Statements and Section 1602, Non-Controlling Interests. These new standards are effective for fiscal years beginning on or after January 1, 2011. As a result of adopting Section 1582, changes in the determination of the fair value of the assets and liabilities of the acquiree will result in a different calculation of goodwill with respect to future acquisitions. 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. Section 1582 will affect the recognition of business combinations completed by the Corporation on or after January 1, 2011 and, as a result, may have a material impact on the Corporation's consolidated earnings and financial position.
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 will result 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 and to the non-controlling interests are required to be separately disclosed on the statement of earnings. The adoption of Sections 1601 and 1602 is not expected to have a material impact on the Corporation's consolidated earnings, cash flows or financial position.
Financial Instruments
In June 2009, the AcSB issued amendments to the CICA Handbook Section 3862, Financial Instruments - Disclosures to include additional disclosure requirements about the fair value measurement of financial instruments and to enhance liquidity risk disclosures. The amendments are effective for annual financial statements relating to fiscal years ending after September 30, 2009. The Corporation will reflect the additional disclosures in its 2009 annual audited consolidated financial statements.
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 that related to contingencies, during the nine months ended September 30, 2009, except for those described in Notes 8, 15 and 22 to these interim consolidated financial statements.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. A description of the nature of the regulatory assets and liabilities is provided below and in Note 4 to the Corporation's 2008 annual audited consolidated financial statements.
As at As at
September 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Assets
Future income taxes (Note 2) 543 -
Rate stabilization accounts - Terasen Gas companies 76 76
Rate stabilization accounts - electric utilities 71 78
Alberta Electric System Operator ("AESO") charges
deferral 62 64
Regulatory other post-employment benefit ("OPEB")
plan asset 57 51
Income taxes recoverable on OPEB plans 18 18
Point Lepreau replacement energy deferral (1) 19 -
Energy management costs 8 7
Southern Crossing Pipeline tax reassessment 7 7
Deferred pension costs 6 7
Deferred capital asset amortization 5 8
Residential unbundling 5 7
Other regulatory assets 47 37
-------------------------------------------------------------------------
Total regulatory assets 924 360
Less: current portion (196) (157)
-------------------------------------------------------------------------
Long-term regulatory assets 728 203
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Maritime Electric has regulatory approval to defer the cost of
replacement energy related to the New Brunswick Power Point Lepreau
Nuclear Generating Station during its refurbishment outage. The nature
and timing of the future recovery of the amount is expected to be
determined by the regulator in the first quarter of 2010.
As at As at
September 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Liabilities
Future asset removal and site restoration provision 341 337
Future income taxes (Note 2) 41 -
Rate stabilization accounts - Terasen Gas companies 25 32
Rate stabilization accounts - electric utilities 18 9
Performance-based rate-setting incentive liabilities 14 13
Unbilled revenue liability 12 15
Southern Crossing Pipeline deferral 6 9
Pension deferral 4 4
Fair value of the foreign exchange forward contract 1 7
Other regulatory liabilities 24 20
-------------------------------------------------------------------------
Total regulatory liabilities 486 446
Less: current portion (36) (45)
-------------------------------------------------------------------------
Long-term regulatory liabilities 450 401
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. INVENTORIES
As at As at
September 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gas in storage 194 212
Materials and supplies 17 17
-------------------------------------------------------------------------
211 229
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the three and nine months ended September 30, 2009, inventories of $98 million and $722 million, respectively, were expensed and reported in energy supply costs in the interim consolidated statement of earnings ($157 million and $850 million for the three and nine months ended September 30, 2008, respectively). Inventories expensed to operating expenses were $3 million and $10 million for the three and nine months ended September 30, 2009, respectively ($4 million and $10 million for the three and nine months ended September 30, 2008, respectively), which included $2 million and $6 million, respectively, for food and beverage costs at Fortis Properties ($2 million and $6 million for the three and nine months ended September 30, 2008, respectively).
7. INTANGIBLE ASSETS
As at September 30, 2009
---------------------------------------------------------------------
---------------------------------------------------------------------
Amortization Net
Rates Accumulated Book
($ millions) (%) Cost Amortization Value
---------------------------------------------------------------------
---------------------------------------------------------------------
Computer software 10-20 322 (164) 158
Land, transmission and
water rights 1-17 131 (38) 93
Franchise fees, customer
contracts and other 3-22 17 (8) 9
Assets under construction 4 - 4
---------------------------------------------------------------------
474 (210) 264
---------------------------------------------------------------------
---------------------------------------------------------------------
As at December 31, 2008
---------------------------------------------------------------------
---------------------------------------------------------------------
Net
Accumulated Book
($ millions) Cost Amortization Value
---------------------------------------------------------------------
---------------------------------------------------------------------
Computer software 313 (144) 169
Land, transmission and water rights 127 (36) 91
Franchise fees, customer contracts
and other 16 (5) 11
Assets under construction 2 - 2
---------------------------------------------------------------------
458 (185) 273
---------------------------------------------------------------------
---------------------------------------------------------------------
There was no impairment of intangible assets for the nine months ended September 30, 2009 and for the year ended December 31, 2008.
Additions to intangible assets for the three and nine months ended September 30, 2009 were $12 million and $23 million, respectively, of which approximately $6 million and $15 million, respectively, were developed internally. During the three and nine months ended September 30, 2009, computer software of $6 million was retired, reducing cost and accumulated amortization.
Included in the cost of land, transmission and water rights is a total of $58 million (December 31, 2008 - $57 million) not subject to amortization.
8. GOODWILL
Annually, the Corporation tests for impairment of goodwill. During 2009, Fortis changed the date of the annual goodwill impairment test from July 31st to October 1st to better correspond with the timing of the preparation of the Corporation's and subsidiaries' annual financial budgets. Accordingly, this accounting change is preferable in the Corporation's circumstance. The change in timing of the test did not delay, accelerate or avoid any impairment charge. The Corporation performed the annual goodwill impairment test as at July 31, 2009 and determined that no goodwill impairment provision was required. The test is being performed again as at October 1, 2009. The change in the timing of the impairment test had no impact on the interim consolidated financial statements for the three and nine months ended September 30, 2009.
9. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at As at
September 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,253 4,934
Long-term classification of committed credit
facilities (Note 20) 160 224
Deferred debt financing costs (39) (34)
-------------------------------------------------------------------------
Total long-term debt and capital lease obligations 5,374 5,124
Less: Current installments of long-term debt and
capital lease obligations (130) (240)
-------------------------------------------------------------------------
5,244 4,884
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In July 2009, Fortis issued 30-year $200 million 6.51% unsecured debentures.
In July 2009, FortisBC repaid $50 million 6.75% debentures that matured.
In June 2009, TGI repaid $60 million 10.75% unsecured debentures that matured.
In June 2009, FortisBC issued 30-year $105 million 6.10% unsecured debentures.
In May 2009, Newfoundland Power issued 30-year $65 million 6.606% first mortgage sinking fund bonds.
In May 2009, Caribbean Utilities closed the first tranche of a 15-year US$40 million private placement of 7.50% senior unsecured notes in the amount of US$30 million, and in July 2009 closed the second tranche of US$10 million.
In February 2009, FortisAlberta issued 30-year $100 million 7.06% unsecured debentures.
In February 2009, TGI issued 30-year $100 million 6.55% unsecured debentures.
During the first quarter of 2009, Fortis began accounting for its investment in the Exploits Partnership using the equity method of accounting (Note 22). As a result, the Exploits Partnership term loan of approximately $60 million (December 31, 2008 - $61 million) classified as current as at December 31, 2008 is no longer being consolidated in the financial statements of Fortis, effective February 13, 2009.
10. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value.
As at As at
Issued and Outstanding September 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares 170,652 2,482 169,191 2,449
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-------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended Year-to-date
September 30, 2009 September 30, 2009
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening balance 170,311 2,474 169,191 2,449
Consumer Share
Purchase Plan 12 - 43 1
Dividend
Reinvestment Plan 275 7 839 20
Employee Share
Purchase Plan 54 1 257 6
Stock Option Plans - - 322 6
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Ending balance 170,652 2,482 170,652 2,482
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Effective March 1, 2009, the Corporation's Amended and Restated Dividend Reinvestment and Share Purchase Plan provides a 2 per cent discount on the purchase of common shares, issued from treasury, with reinvested dividends.
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 170.4 million and 157.2 million for the quarters ended September 30, 2009 and September 30, 2008, respectively, and 170.0 million and 156.9 million year-to-date September 30, 2009 and September 30, 2008, 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 are as follows:
Quarter Ended September 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic
Earnings
per Common
Share 36 170.4 $0.21 49 157.2 $0.31
Effect of
potential
dilutive
securities:
Stock options - 0.7 - 1.0
Preference
shares (Note 14) 4 13.9 4 12.8
Convertible
debentures 1 1.4 1 1.4
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41 186.4 54 172.4
Deduct
anti-dilutive
impacts:
Preference
shares (4) (13.9) (4) (12.8)
Convertible
debentures (1) (1.4) (1) (1.4)
---------------------------------------------------------------------------
Diluted Earnings
per Common Share 36 171.1 $0.21 49 158.2 $0.31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date September 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic Earnings
per Common
Share 181 170.0 $1.06 169 156.9 $1.08
Effect of
potential
dilutive
securities:
Stock options - 0.7 - 1.0
Preference
shares
(Note 14) 12 13.9 12 12.8
Convertible
debentures 2 1.4 2 1.4
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195 186.0 183 172.1
Deduct
anti-dilutive
impacts:
Convertible
debentures (2) (1.4) (2) (1.4)
---------------------------------------------------------------------------
Diluted Earnings
per Common
Share 193 184.6 $1.05 181 170.7 $1.06
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11. STOCK-BASED COMPENSATION PLANS
During the nine months ended September 30, 2009, 30,336 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the equity component of their annual compensation and their annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation. In January 2009, 3,632 DSUs were paid out to a retired member of the Board of Directors of Fortis at $23.74 per DSU for a total of approximately $0.1 million.
In March 2009, 31,353 Performance Share Units ("PSUs") were paid out to the President and Chief Executive Officer ("CEO") of the Corporation, as determined by the Human Resources Committee of the Board of Directors of Fortis, at $23.39 per PSU for a total of approximately $0.7 million. The payout was made upon the three-year maturation period in respect of the PSU grant made in March 2006 and the President and CEO satisfying the payment requirements. In March 2009, 40,000 PSUs were granted to the President and CEO of the Corporation. Each 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 2009 PSU grant is three years, at which time a cash payment is made to the President and CEO after evaluation by the Human Resources Committee of the Board of Directors of Fortis of the achievement of pre-determined personal and/or corporate objectives.
In March 2009, the Corporation granted 1,037,156 options to purchase common shares under its 2006 Stock Option Plan at the five-day volume weighted average trading price of $22.29 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 $4.10 per option.
The fair value was estimated on the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
Dividend yield (%) 3.19
Expected volatility (%) 24.3
Risk-free interest rate (%) 3.75
Weighted average expected life (years) 4.5
At September 30, 2009, 4.9 million stock options were outstanding and 2.7 million stock options were vested.
12. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency translation gains and losses, net of hedging activities, gains and losses on cash flow hedging activities and gains and losses on discontinued cash flow hedging activities.
Quarter Ended
September 30, 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) July 1 change September 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains, net
of hedging activities and tax (55) (19) (74)
Losses on derivative instruments
designated as cash flow hedges, net of tax - - -
Net losses on derivative instruments
previously discontinued as cash flow
hedges, net of tax (5) - (5)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (60) (19) (79)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter Ended
September 30, 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) July 1 change September 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains, net
of hedging activities and tax (78) 7 (71)
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)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (84) 7 (77)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-date 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change September 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains, net
of hedging activities and tax (46) (28) (74)
(Losses) gains 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)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (52) (27) (79)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-date 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change September 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains, net of
hedging activities and tax (82) 11 (71)
(Losses) gains 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)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (88) 11 (77)
--------------------------------------------------------------------------
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13. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans, defined contribution pension plans and group registered retirement savings plans ("RRSPs") for its employees. The cost of providing the defined benefit arrangements was $7 million for the quarter ended September 30, 2009 ($7 million for the quarter ended September 30, 2008) and $20 million year-to-date September 30, 2009 ($21 million year-to-date September 30, 2008). The cost of providing the defined contribution arrangements and group RRSPs was $3 million for the quarter ended September 30, 2009 ($3 million for the quarter ended September 30, 2008) and $9 million year-to-date September 30, 2009 ($8 million year-to-date September 30, 2008).
14. FINANCE CHARGES
Quarter Ended Year-to-date
September 30 September 30
($ millions) 2009 2008 2009 2008
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-------------------------------------------------------------------------
Interest
- Long-term debt and
capital lease
obligations 89 80 259 248
- Short-term borrowings 3 10 9 20
Interest charged to
construction (5) (4) (13) (8)
Interest earned - (1) - (2)
Dividends on preference
shares classified as
debt 4 4 12 12
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91 89 267 270
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15. CORPORATE TAXES
Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and Newfoundland Power used the taxes payable method of accounting for income taxes. The effect on the Corporation's consolidated financial statements, as at January 1, 2009, of adopting amended Section 3465, Income Taxes included an increase in total future income tax liabilities and total future income tax assets of $491 million and $24 million, respectively; an increase in regulatory assets and regulatory liabilities of $535 million and $59 million, respectively; and a combined $9 million net increase in income taxes payable, deferred credits, other assets, utility capital assets and goodwill, associated with the reclassification of future income taxes that were previously netted against these respective balance sheet items. Included in the future income tax assets and liabilities recorded are the future income tax effects of the subsequent settlement of the related regulatory assets and liabilities through customer rates.
Future income taxes are provided for temporary differences. Future income tax assets and liabilities are comprised of the following:
As at As at
September 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future income tax liability (asset)
Utility capital assets 492 17
Income producing properties 27 26
Regulatory assets 42 35
Intangible assets 7 3
Other assets 25 2
Deferred credits (43) (14)
Loss carryforwards (30) (28)
Share issue and debt financing costs (5) (14)
Unrealized foreign currency translation losses on
long-term debt 4 (5)
Regulatory liabilities (2) -
-------------------------------------------------------------------------
Net future income tax liability 517 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current future income tax asset (17) -
Current future income tax liability 17 15
Long-term future income tax asset (29) (54)
Long-term future income tax liability 546 61
-------------------------------------------------------------------------
Net future income tax liability 517 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The adoption of amended Section 3465, Income Taxes on January 1, 2009 also resulted in additional future income tax expense of $12 million for the quarter ended September 30, 2009 and $11 million year-to-date September 30, 2009 and offsetting regulatory adjustments to future income tax expense of the same amounts during those periods. The regulatory adjustment represents the difference between the future income tax expense recognized under amended Section 3465, Income Taxes and that recovered from customers in rates during the quarter and year-to-date period ended September 30, 2009.
The components of the provision for corporate taxes are as follows:
Quarter Ended Year-to-date
September 30 September 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Canadian
Current taxes $- $(2) $24 $30
-------------------------------------------------------------------------
Future income taxes 14 2 20 16
Less regulatory
adjustment (12) - (11) -
-------------------------------------------------------------------------
2 2 9 16
-------------------------------------------------------------------------
Total Canadian 2 - 33 46
-------------------------------------------------------------------------
Foreign
Current taxes - - 1 1
Future income taxes - - - 1
-------------------------------------------------------------------------
Total Foreign - - 1 2
-------------------------------------------------------------------------
Corporate taxes $2 $- $34 $48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory tax rate to earnings before corporate taxes and non-controlling interest. The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.
Quarter Ended Year-to-date
($ millions, except September 30 September 30
as noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Combined Canadian
federal and
provincial statutory
income tax rate 33% 33.5% 33% 33.5%
-------------------------------------------------------------------------
Statutory income tax
rate applied to
earnings before
corporate taxes and
non-controlling interest $16 $19 $79 $78
Preference share
dividends 1 - 4 4
Difference between
Canadian statutory
rate and rates
applicable to foreign
subsidiaries (5) (5) (12) (7)
Difference in Canadian
provincial statutory
rates applicable to
subsidiaries in
different Canadian
jurisdictions (1) - (5) (3)
Items capitalized for
accounting but
expensed for income
tax purposes (7) (8) (27) (25)
Difference between
capital cost allowance
and amounts claimed
for accounting purposes (1) (2) (1) 3
Quebec Tax Trust tax
settlement - Terasen - (7) - (7)
Pension costs - - (1) (1)
Other (1) 3 (3) 6
-------------------------------------------------------------------------
Corporate taxes $2 $- $34 $48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effective tax rate 4.3% N/A 14.3% 20.5%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at September 30, 2009, the Corporation had approximately $120 million (December 31, 2008 - $112 million) in non-capital and capital loss carryforwards of which $16 million (December 31, 2008 - $15 million) has not been recognized in the consolidated financial statements. The non-capital loss carryforwards expire between 2009 and 2029.
16. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Quarter Terasen
ended Gas Total
September Companies- Fortis Fortis NF Other Electric Electric
30, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 208 85 57 93 69 304 89
Energy
supply costs 98 - 15 50 46 111 51
Operating
expenses 60 33 17 12 7 69 13
Amortization 25 25 9 12 5 51 9
---------------------------------------------------------------------------
Operating income 25 27 16 19 11 73 16
Finance charges 30 12 8 8 4 32 5
Corporate taxes
(recovery) (2) (1) - 4 2 5 -
Non-controlling
interest - - - - - - 4
---------------------------------------------------------------------------
Net (loss)
earnings (3) 16 8 7 5 36 7
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net (loss)
earnings
applicable to
common shares (3) 16 8 7 5 36 7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 144
Identifiable
assets 3,840 1,814 1,122 1,156 540 4,632 803
---------------------------------------------------------------------------
Total assets 4,748 2,041 1,343 1,156 603 5,143 947
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 62 109 30 20 10 169 27
---------------------------------------------------------------------------
Quarter ended
September 30,
2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 271 74 52 94 66 286 96
Energy supply
costs 157 - 12 51 44 107 60
Operating
expenses 59 31 16 11 7 65 12
Amortization 24 22 8 11 4 45 8
---------------------------------------------------------------------------
Operating income 31 21 16 21 11 69 16
Finance charges 33 10 7 8 4 29 4
Corporate taxes
(recovery) (3) (6) 1 5 2 2 1
Non-controlling
interest - - - - - - 4
---------------------------------------------------------------------------
Net earnings
(loss) 1 17 8 8 5 38 7
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 1 17 8 8 5 38 7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 139
Identifiable
assets 3,510 1,482 958 971 513 3,924 759
---------------------------------------------------------------------------
Total assets 4,419 1,709 1,179 971 576 4,435 898
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 56 94 31 17 11 153 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter ended Corporate Inter-
September 30, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
---------------------------------------------------------------------------
Revenue 9 60 7 (13) 664
Energy supply costs 1 - - (8) 253
Operating expenses 2 37 2 (1) 182
Amortization - 4 2 - 91
---------------------------------------------------------------------------
Operating income 6 19 3 (4) 138
Finance charges 1 6 21 (4) 91
Corporate taxes
(recovery) 1 4 (6) - 2
Non-controlling interest - - - - 4
---------------------------------------------------------------------------
Net (loss) earnings 4 9 (12) - 41
Preference share
dividends - - 5 - 5
---------------------------------------------------------------------------
Net (loss) earnings
applicable to common
shares 4 9 (17) - 36
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,563
Identifiable assets 202 574 149 (36) 10,164
---------------------------------------------------------------------------
Total assets 202 574 149 (36) 11,727
---------------------------------------------------------------------------
Gross capital
expenditures (3) 2 6 1 - 267
---------------------------------------------------------------------------
Quarter ended
September 30, 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 21 56 7 (10) 727
Energy supply costs 2 - - (6) 320
Operating expenses 3 33 2 - 174
Amortization 3 4 2 - 86
---------------------------------------------------------------------------
Operating income 13 19 3 (4) 147
Finance charges 2 6 19 (4) 89
Corporate taxes
(recovery) 2 4 (6) - -
Non-controlling interest - - - - 4
---------------------------------------------------------------------------
Net earnings (loss) 9 9 (10) - 54
Preference share
dividends - - 5 - 5
---------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 9 9 (15) - 49
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,559
Identifiable assets 262 537 115 (29) 9,078
---------------------------------------------------------------------------
Total assets 262 537 115 (29) 10,637
---------------------------------------------------------------------------
Gross capital
expenditures (3) 6 3 1 - 250
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties and
intangible assets
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Year-to- Terasen
date Gas Total
September Companies- Fortis Fortis NF Other Electric Electric
30, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 1,166 245 184 381 202 1,012 254
Energy supply
costs 722 - 50 247 133 430 142
Operating
expenses 189 98 51 39 21 209 41
Amortization 76 70 28 34 14 146 29
---------------------------------------------------------------------------
Operating income 179 77 55 61 34 227 42
Finance charges 91 36 23 25 13 97 13
Corporate taxes
(recovery) 19 (4) 3 12 7 18 1
Non-controlling
interest - - - - - - 8
---------------------------------------------------------------------------
Net earnings
(loss) 69 45 29 24 14 112 20
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 69 45 29 24 14 112 20
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 144
Identifiable
assets 3,840 1,814 1,122 1,156 540 4,632 803
---------------------------------------------------------------------------
Total assets 4,748 2,041 1,343 1,156 603 5,143 947
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 176 315 79 52 33 479 77
---------------------------------------------------------------------------
Year-to-date
September 30,
2008
---------------------------------------------------------------------------
Revenue 1,296 222 171 378 197 968 249
Energy supply
costs 850 - 45 243 133 421 164
Operating
expenses 182 96 49 38 21 204 35
Amortization 73 63 25 33 13 134 23
---------------------------------------------------------------------------
Operating
income 191 63 52 64 30 209 27
Finance charges 96 30 21 25 13 89 11
Corporate taxes
(recovery) 24 (2) 4 15 6 23 1
Non-controlling
interest - - - - - - 6
---------------------------------------------------------------------------
Net earnings
(loss) 71 35 27 24 11 97 9
Preference
share dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 71 35 27 24 11 97 9
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 139
Identifiable
assets 3,510 1,482 958 971 513 3,924 759
---------------------------------------------------------------------------
Total assets 4,419 1,709 1,179 971 576 4,435 898
---------------------------------------------------------------------------
Gross capital
expenditures
(3) 152 245 81 47 28 401 65
---------------------------------------------------------------------------
NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date Corporate Inter-
September 30, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
---------------------------------------------------------------------------
Revenue 34 165 21 (33) 2,619
Energy supply costs 2 - - (17) 1,279
Operating expenses 8 109 9 (4) 561
Amortization 4 12 7 - 274
---------------------------------------------------------------------------
Operating income 20 44 5 (12) 505
Finance charges 3 17 58 (12) 267
Corporate taxes
(recovery) 3 8 (15) - 34
Non-controlling interest 1 - - - 9
---------------------------------------------------------------------------
Net earnings (loss) 13 19 (38) - 195
Preference share
dividends - - 14 - 14
---------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 13 19 (52) - 181
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,563
Identifiable assets 202 574 149 (36) 10,164
---------------------------------------------------------------------------
Total assets 202 574 149 (36) 11,727
---------------------------------------------------------------------------
Gross capital
expenditures (3) 14 16 1 - 763
---------------------------------------------------------------------------
Year-to-date
September 30,
2008
---------------------------------------------------------------------------
Revenue 62 155 19 (28) 2,721
Energy supply costs 6 - - (14) 1,427
Operating expenses 11 99 8 (4) 535
Amortization 8 11 6 - 255
---------------------------------------------------------------------------
Operating income 37 45 5 (10) 504
Finance charges 6 18 60 (10) 270
Corporate taxes
(recovery) 7 8 (15) - 48
Non-controlling interest 2 - - - 8
---------------------------------------------------------------------------
Net earnings (loss) 22 19 (40) - 178
Preference share
dividends - - 9 - 9
---------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 22 19 (49) - 169
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,559
Identifiable assets 262 537 115 (29) 9,078
---------------------------------------------------------------------------
Total assets 262 537 115 (29) 10,637
---------------------------------------------------------------------------
Gross capital
expenditures (3) 13 11 4 - 646
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties and
intangible assets
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 and FortisOntario, electricity sales from Newfoundland Power to Fortis Properties and finance charges on inter-segment borrowings. The significant inter-segment transactions for the three and nine months ended September 30, 2009 and 2008 were as follows.
Inter-Segment Transactions
Quarter Ended Year-to-date
September 30 September 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
Sales from Fortis
Generation to
Regulated Electric
Utilities - Caribbean 7 6 15 13
Sales from Fortis
Generation to Other
Canadian Electric
Utilities - - 1 1
Sales from Newfoundland
Power to Fortis
Properties 1 1 3 3
Inter-segment finance
charges on borrowings
from:
Corporate to Regulated
Electric Utilities
- Canadian - - 1 1
Corporate to Regulated
Electric Utilities
- Caribbean 2 1 5 3
Corporate to Fortis
Properties 2 2 6 6
-------------------------------------------------------------------------
17. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-date
September 30 September 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
Interest paid 88 85 272 266
Income taxes paid 2 22 82 32
-------------------------------------------------------------------------
18. 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 in support of infrastructure investment 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 utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
As at As at
September 30, 2009 December 31, 2008
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total debt and
capital lease
obligations
(net of cash) (1) 5,604 59.8 5,468 59.5
Preference
shares (2) 667 7.1 667 7.3
Common shareholders'
equity 3,100 33.1 3,046 33.2
-------------------------------------------------------------------------
Total 9,371 100.0 9,181 100.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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
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. Fortis and its subsidiaries, except for Belize Electricity and the Exploits Partnership, as described below, were in compliance with their debt covenants as at September 30, 2009.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009 Rate Application, Belize Electricity does not meet certain debt covenant financial ratios related to loans totalling $7 million (BZ$13 million), as at September 30, 2009, with the International Bank for Reconstruction and Development and the Caribbean Development Bank. The Company has informed the lenders of the defaults.
As the hydroelectric assets and water rights of the Exploits Partnership had been provided as security for the Exploits Partnership's 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 loan is without recourse to Fortis and was approximately $60 million as at September 30, 2009. The lenders of the term loan have not demanded accelerated repayment. See Notes 9 and 22 for further information on the Exploits Partnership.
The Corporation's consolidated credit facilities are discussed further under "Liquidity Risk" in Note 20.
19. FINANCIAL INSTRUMENTS
Fair Values
There was no change during the nine months ended September 30, 2009 in the designation of the Corporation's financial instruments from that disclosed in the Corporation's 2008 annual audited consolidated financial statements. The carrying values of financial instruments included in current assets, current liabilities, other assets and deferred credits in the consolidated balance sheets of Fortis approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or the nature of these instruments. The carrying values and fair values of the Corporation's consolidated long-term debt and preference shares were as follows:
As at As at
September 30, 2009 December 31, 2008
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
-------------------------------------------------------------------------
Long-term debt,
including current
portion (1) (2) 5,376 5,803 5,122 5,040
Preference shares,
classified as
debt (1) (3) 320 348 320 329
-------------------------------------------------------------------------
(1) Carrying value is measured at amortized cost using the effective
interest rate method.
(2) Carrying value as at September 30, 2009 excludes unamortized deferred
financing costs of $39 million (December 31, 2008 - $34 million).
(3) Preference shares classified as equity are excluded from the
requirements of the CICA Handbook Section 3855, Financial Instruments,
Recognition and Measurement; however, the estimated fair value of the
Corporation's $347 million preference shares classified as equity was
$343 million as at September 30, 2009 (December 31, 2008 - carrying
value $347 million; fair value $268 million).
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, the fair value is determined by discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills, with similar terms to maturity, plus a market credit risk premium equal to that of issuers of similar credit quality. Since the Corporation does not intend to settle the long-term debt prior to maturity, the fair value estimate does not represent an actual liability and, therefore, does not include exchange or settlement costs. The fair value of the Corporation's preference shares is determined using quoted market prices.
The Corporation and its subsidiaries hedge exposures to fluctuations in interest rates, foreign exchange rates and natural gas prices through the use of derivative financial instruments. The Corporation does not hold or issue derivative financial instruments for trading purposes. The following table summarizes the valuation of the Corporation's derivative financial instruments.
As at As at
September 30, 2009 December 31, 2008
Term to Number Carrying Estimated Carrying Estimated
maturity of Value Fair Value Value Fair Value
Asset (years) Contracts ($ ($ ($ ($
(Liability) millions) millions) millions) millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest
rate swap(1) 1 1 - - - -
Foreign
exchange
forward
contract(2) approx.
2 1 1 1 7 7
Natural gas
derivatives:
(3)
Swaps and
options Up to 5 254 (129) (129) (84) (84)
Gas
purchase
contract
premiums Up to 2 98 3 3 (8) (8)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) The 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. The contract
was valued at the present value of future cash flows based on published
forward future interest rate curves.
(2) The fair value of the foreign exchange forward contract was calculated
using the present value of cash flows based on a market foreign
exchange rate and the foreign exchange forward rate curve and was
recorded in accounts receivable as at September 30, 2009 and December
31, 2008.
(3) The fair values of the natural gas derivatives were calculated using
the present value of cash flows based on market prices and forward
curves for the commodity cost of natural gas and were recorded in
accounts payable as at September 30, 2009 and December 31, 2008.
The fair value of the Corporation's financial instruments, including derivatives, reflects a point-in-time estimate 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 earnings or cash flows.
20. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
Credit risk: Risk that a 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 market risks
related to foreign exchange, interest rates and commodity
prices.
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 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 and these 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 September 30, 2009, its gross credit risk exposure was approximately $89 million, representing the projected value of retailer billings over a 60-day period. The Company has reduced its exposure to approximately $2 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency or by having the retailer obtain a financial guarantee from an entity with an investment-grade credit rating.
The Terasen Gas companies are exposed to credit risk in the event of non-performance by counterparties to derivative financial instruments, including natural gas derivatives. The Terasen Gas companies are also exposed to significant credit risk on physical off-system sales. To mitigate credit risk, the Terasen Gas companies deal with high credit-quality institutions, in accordance with established credit-approval practices. The counterparties with which the Terasen Gas companies have significant transactions are A-rated entities or better. The Company uses netting arrangements to reduce credit risk and net settles payments with counterparties where net settlement provisions exist.
The aging analysis of the Corporation's consolidated accounts receivable (excluding derivative financial instruments recorded in accounts receivable) is as follows:
As at As at As at As at As at
September 30, June 30, March 31, December 31, September 30,
($ millions) 2009 2009 2009 2008 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Not past due 305 367 610 587 396
Past due 0-30 days 35 53 93 70 43
Past due 31-60 days 11 22 23 14 9
Past due 61 days
and over 22 21 20 19 23
--------------------------------------------------------------------------
373 463 746 690 471
Less: allowance for
doubtful accounts (17) (18) (19) (16) (14)
--------------------------------------------------------------------------
356 445 727 674 457
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at September 30, 2009, 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 financial position could be adversely affected if it, or its operating subsidiaries, fail 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 results of operations and financial position of the Corporation and its subsidiaries, conditions in the capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.
To 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 committed credit facility at Fortis is also 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 September 30, 2009, consolidated long-term debt maturities and repayments are expected to average approximately $157 million annually over each of the next five years. The combination of available credit facilities and low annual debt maturities and repayments provide the Corporation and its subsidiaries with flexibility in the timing and access to capital markets.
As at September 30, 2009, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.2 billion, of which approximately $1.6 billion was unused. The credit facilities are syndicated almost entirely with the seven largest Canadian banks with no one bank holding more than 25 per cent of these facilities.
The following table summarizes the credit facilities of the Corporation and its subsidiaries.
Total as at Total as at
Corporate Regulated Fortis September 30, December 31,
($ millions) and Other Utilities Properties 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 645 1,496 13 2,154 2,228
Credit
facilities
utilized:
Short-term
borrowings - (335) (1) (336) (410)
Long-term debt
(Note 9) - (160) - (160) (224)
Letters of credit
outstanding (1) (98) (1) (100) (104)
--------------------------------------------------------------------------
Credit facilities
available 644 903 11 1,558 1,490
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at September 30, 2009 and December 31, 2008, certain borrowings under the Corporation's and/or subsidiaries' credit facilities have been 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.
Corporate and Other
In May 2009, Terasen entered into a $30 million committed revolving credit facility maturing in May 2011 to replace its $100 million committed revolving credit facility that matured in May 2009. The terms of the new credit facility are substantially the same as those of the credit facility it replaced.
Regulated Utilities
On April 30, 2009, FortisBC amended its $150 million unsecured committed revolving credit facility, including extending the maturity date of the $50 million portion of the facility to May 2012 from May 2011 and extending the maturity date of the $100 million portion of the facility to May 2010 from May 2009.
In March 2009, Maritime Electric renegotiated its $50 million demand credit facility and had it converted into a 364-day revolving committed credit facility.
The following is an analysis of the contractual maturities of the Corporation's consolidated financial liabilities, including derivatives, as at September 30, 2009.
Financial Liabilities
Due Due in Due in
within years 2 years 4 Due after
($ millions) 1 year and 3 and 5 5 years Total
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Short-term borrowings 336 - - - 336
Trade and other accounts
payable 586 - - - 586
Natural gas derivatives (1) 99 26 4 - 129
Foreign exchange forward
contract (2) 23 3 - - 26
Dividends payable 47 - - - 47
Customer deposits (3) 2 4 1 2 9
Long-term debt, including
current portion (4) 127 368 288 4,593 5,376
Interest obligations on
long-term debt 344 655 633 4,859 6,491
Preference shares, classified
as debt - - 123 197 320
Dividend obligations on
preference shares, classified
as interest expense 17 33 26 19 95
--------------------------------------------------------------------------
1,581 1,089 1,075 9,670 13,415
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at September 30, 2009 at
$126 million.
(2) Amounts disclosed are on a gross cash flow basis. The contract was
recorded in accounts receivable at fair value as at September 30, 2009
at $1 million.
(3) Customer deposits were recorded in deferred credits as at September 30,
2009.
(4) Excluding deferred financing costs of $39 million
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, its 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 in 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 equals US$1.00.
As at September 30, 2009, the Corporation's corporately held US$390 million long-term debt had been designated as a hedge of a portion of the Corporation's foreign net investments. As at September 30, 2009, the Corporation had approximately US$169 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.
TGVI's US dollar payments under a contract for the construction of a liquefied natural gas storage facility expose TGVI to fluctuations in the US dollar-to-Canadian dollar exchange rate. TGVI entered into a foreign exchange forward contract to hedge this exposure. TGVI has regulatory approval to defer any increase or decrease in the fair value of the foreign exchange forward contract for recovery from, or refund to, customers in future rates.
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 September 30, 2009, Fortis Properties was a party to one interest rate swap agreement that effectively fixed the interest rate on variable-rate borrowings. One of Fortis Properties' interest rate swaps matured in July 2009.
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 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.
21. BUSINESS ACQUISITION
Holiday Inn Select - Windsor
In April 2009, Fortis Properties purchased the Holiday Inn Select in Windsor, Ontario for an aggregate cash purchase price of approximately $7 million, including acquisition costs. The acquisition has been accounted for using the purchase method, whereby the results of operations have been consolidated in the financial statements of Fortis commencing April 2009.
The purchase price allocation to assets, based on their fair values, was as follows:
($ millions) Total
---------------------------------------------
Fair value assigned to net assets:
Income producing properties 7
---------------------------------------------
22. 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.
The Corporation's contingent liabilities are consistent with those disclosed in the Corporation's 2008 annual audited consolidated financial statements, except for those described below.
Exploits Partnership
The Exploits Partnership operated two non-regulated hydroelectric generation plants in Newfoundland with a combined capacity of approximately 140 MW. The Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent by Abitibi. In December 2008, the Government of Newfoundland and Labrador expropriated Abitibi's hydroelectric assets and water rights in Newfoundland, including those of the Exploits Partnership. The newsprint mill closed in Grand Falls-Windsor on February 12, 2009, subsequent to which the day-to-day operations of the Exploits Partnership's hydroelectric generating facilities were assumed by Nalcor Energy, a Crown corporation, as an agent for the Government of Newfoundland and Labrador. The loss of control over cash flows and operations required Fortis to report its investment in the Exploits Partnership using the equity method of accounting, effective February 13, 2009. Equity earnings recognized year-to-date 2009 are equivalent to the amounts that would have been recognized under normal hydrology in the absence of the expropriation. Discussions between Fortis Properties and Nalcor Energy with respect to expropriation matters are ongoing.
Terasen
On July 16, 2009, Terasen was named, along with other defendants, in an action related to damages to property and chattels, including contamination to sewer lines and costs associated with remediation, related to a pipeline rupture in July 2007. Terasen has filed a statement of defence but the claim is in its early stages and the amount and outcome of it is indeterminable at this time.
Commitments
There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2008 annual audited consolidated financial statements, except for those described below.
The Terasen's Gas Companies' gas purchase contract obligations increased significantly between September 30, 2009 and December 31, 2008 due to the required increase of inventory in storage for the winter associated with seasonality of the business.
Maritime Electric's take-or-pay contract with New Brunswick Power ("NB Power"), which includes replacement energy and capacity for the NB Power Point Lepreau Nuclear Generating Station during its refurbishment outage, was extended to December 2010. The contract previously expired on March 31, 2009. As at September 30, 2009, the contract totalled approximately $60 million to December 2010.
Fortis Turks and Caicos has entered into an agreement with a supplier to purchase two diesel-generating engines with a combined capacity of approximately 17.5 MW for approximately US$12 million (CDN$13 million) for delivery in April 2010 and January 2011.
Belize Electricity has entered into a new 15-year power purchase agreement with Belize Aquaculture Limited ("BAL"). The agreement provides for the supply of up to 15 MW of capacity by BAL and expires in April 2024. As at September 30, 2009, the agreement totalled approximately $252 million to 2024.
Based on the latest completed actuarial valuations, the Corporation's consolidated defined benefit pension plan funding contributions, including current service, solvency and special funding amounts, are expected to total approximately $22 million for 2009, $18 million for 2010, $6 million for 2011, $3 million for 2012 and $2 million for 2013. These pension funding amounts include additional obligations determined under December 31, 2008 actuarial valuations, completed in the first quarter of 2009, associated with defined benefit pension plans at Newfoundland Power and the Corporation, and under a December 31, 2007 actuarial valuation of a defined benefit pension plan at Terasen, also completed in the first quarter of 2009.
23. SUBSEQUENT EVENTS
In October 2009, FortisOntario closed its acquisition of Great Lakes Power Distribution Inc., subsequently renamed Algoma Power, for an aggregate purchase price of approximately $75 million, including cash acquired, subject to adjustment. Algoma Power is a regulated electric distribution utility serving approximately 12,000 customers in the district of Algoma in Northern Ontario.
In October 2009, FortiaAlberta issued 30-year $125 million 5.37% unsecured debentures, the net proceeds of which will be used to repay committed credit facility borrowings that were incurred primarily to finance capital expenditures, and for general corporate purposes.
24. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period classifications, the most significant of which was the reclassification of $48 million from other assets to utility capital assets on the consolidated balance sheet as at December 31, 2008 related to the net book value of amounts paid to AESO for transmission capital projects at FortisAlberta.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with total assets approaching $12 billion and annual revenues totalling $3.9 billion. The Corporation serves more than 2,000,000 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 hotels and commercial real estate across Canada. Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the symbol FTS.
Share Transfer Agent and Registrar:
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
Additional information, including the Fortis 2008 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
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