Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter
net earnings attributable to common equity shareholders of $55 million, or $0.32
per common share, up $2 million from $53 million, or $0.31 per common share, for
the second quarter of 2009. Year-to-date net earnings attributable to common
equity shareholders were $155 million, or $0.90 per common share, up $10 million
from earnings of $145 million, or $0.85 per common share, for the same period
last year.
Performance for the quarter was driven by the Terasen Gas companies and
FortisBC, partially offset by higher corporate expenses.
The Terasen Gas companies contributed earnings of $17 million, up $3 million
from the second quarter of 2009, mainly due to an increase in the allowed rate
of return on common equity ("ROE") and an increase to the common equity
component of total capital structure ("equity component") at Terasen Gas Inc.
("TGI"). Due to the seasonality of the business, earnings of the Terasen Gas
companies are highest in the first and fourth quarters.
Canadian Regulated Electric Utilities contributed earnings of $40 million, up $1
million from the second quarter of 2009. The increase related to the higher
contribution from FortisBC as a result of a higher allowed ROE and growth in
electrical infrastructure investment, partially offset by lower electricity
sales due to cooler weather experienced in June 2010. Earnings at FortisAlberta
were comparable quarter over quarter. The impact of FortisAlberta's higher
allowed ROE and equity component, compared to those reflected in earnings for
the second quarter of 2009, combined with growth in electrical infrastructure
investment and customers, was mainly offset by lower corporate income tax
recoveries and lower net transmission revenue.
Caribbean Regulated Electric Utilities contributed $7 million to earnings,
comparable to earnings for the second quarter of 2009. Excluding the approximate
$1 million unfavourable impact of foreign exchange rates associated with the
weakening of the US dollar quarter over quarter, earnings were approximately $1
million higher quarter over quarter. The increase was mainly associated with
electricity sales growth, due to warmer weather, customer growth and improving
tourism in the Turks and Caicos Islands, partially offset by higher business
taxes at Belize Electricity and increased finance charges.
Non-Regulated Fortis Generation contributed $3 million to earnings, comparable
to earnings for the second quarter of 2009. Excluding the approximate $1 million
unfavourable impact of foreign exchange rates, earnings were approximately $1
million higher quarter over quarter. The increase in earnings was mainly
attributable to higher hydroelectric production in Belize quarter over quarter,
driven by the Vaca hydroelectric generating facility commissioned in March 2010,
and lower finance charges.
Fortis Properties delivered earnings of $8 million, consistent with earnings for
the second quarter of 2009.
Corporate and other expenses were $20 million compared to $18 million for the
same quarter in 2009. The increase was mainly due to dividends associated with
the First Preference Shares, Series H issued in January 2010 and higher business
development costs, partially offset by higher interest income related to
increased inter-company lending.
Proceeds from the $250 million five-year fixed rate reset preference shares
issued in January 2010 were used to repay borrowings under the Corporation's
committed credit facility and to fund an equity injection into TGI to repay
borrowings under the Company's credit facilities.
In April, Terasen Inc. redeemed in full for cash its $125 million 8.0% Capital
Securities.
Consolidated capital expenditures, before customer contributions, were
approximately $432 million for the first half of 2010.
Cash flow from operating activities was $453 million year to date compared to
$504 million for the same period last year. The decrease was driven by changes
in working capital at the Terasen Gas companies, partially offset by higher
earnings period over period.
As at June 30, 2010, Fortis had consolidated credit facilities of approximately
$2.1 billion, of which $1.4 billion was unused, including $403 million unused
under the Corporation's $600 million committed revolving credit facility.
Approximately $2.0 billion of the total credit facilities are committed
facilities, the majority of which currently have maturities between 2011 and
2013.
In April, FortisBC obtained an extension to the maturity of its $150 million
unsecured committed credit facility with $100 million now maturing in May 2013
and $50 million now maturing in May 2011. In May, Terasen Gas (Vancouver Island)
Inc. ("TGVI") entered into a two-year $300 million unsecured committed credit
facility replacing its former $350 million credit facility due to mature in
January 2011.
During the second quarter, Standard & Poor's and DBRS confirmed the
Corporation's existing debt credit ratings at A-(stable) and BBB(high),
respectively.
"Our subsidiaries are focused on completing their capital projects for 2010,
estimated to exceed $1 billion," says Stan Marshall, President and Chief
Executive Officer, Fortis Inc. "Much of this investment is occurring at our
utilities in western Canada. The largest projects well underway include
construction of the liquefied natural gas storage facility at TGVI, the
installation of automated meters at FortisAlberta and the Okanagan Transmission
Reinforcement Project at FortisBC," he explains.
"The priority of Fortis is to meet our obligation to serve customers," says
Marshall. "We will continue to build our business profitably through ongoing
investment in existing operations and the pursuit of strategic acquisitions of
regulated electric and gas utilities in the United States, Canada and the
Caribbean," concludes Marshall.
FORWARD-LOOKING STATEMENT
The following analysis should be read in conjunction with the Fortis Inc.
("Fortis" or the "Corporation") interim unaudited consolidated financial
statements and notes thereto for the three and six months ended June 30, 2010
and the Management Discussion and Analysis ("MD&A") and audited consolidated
financial statements for the year ended December 31, 2009 included in the
Corporation's 2009 Annual Report. This material has been prepared in accordance
with National Instrument 51-102 - Continuous Disclosure Obligations relating to
MD&As. Financial information in this release has been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP") and is
presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of
applicable securities laws in Canada ("forward-looking information"). The
purpose of the forward-looking information is to provide management's
expectations regarding the Corporation's future growth, results of operations,
performance, business prospects and opportunities, and it may not be appropriate
for other purposes. All forward-looking information is given pursuant to the
"safe harbour" provisions of applicable Canadian securities legislation. The
words "anticipates", "believes", "budgets", "could", "estimates", "expects",
"forecasts", "intends", "may", "might", "plans", "projects", "schedule",
"should", "will", "would" and similar expressions are often intended to identify
forward-looking information, although not all forward-looking information
contains these identifying words. The forward-looking information reflects
management's current beliefs and is based on information currently available to
the Corporation's management. The forward-looking information in the MD&A
includes, but is not limited to, statements regarding: the expected timing of
the recording of the effects of the regulatory decision on FortisAlberta's 2010
and 2011 revenue requirements application; the expected decrease in the total
costs of FortisAlberta's automated meter reading technology project; expected
consolidated forecasted gross capital expenditures for 2010 and in total over
the five-year period from 2010 through 2014; the expectation that the
Corporation's significant capital program should drive growth in earnings and
dividends; the expected increase in average annual energy production from the
Macal River in Belize by the Vaca hydroelectric generating facility; expected
consolidated long-term debt maturities and repayments on average annually over
the next five years; the expectation of no material adverse credit rating
actions in the near term; expected sources of financing for the subsidiaries'
capital expenditure programs; the expectation that Fortis will elect to defer
the adoption of IFRS until 2013; and except for debt at Belize Electricity and
Exploits River Hydro Partnership ("Exploits Partnership"), the expectation that
the Corporation and its subsidiaries will remain compliant with debt covenants
during 2010.
The forecasts and projections that make up the forward-looking information are
based on assumptions which include, but are not limited to: the receipt of
applicable regulatory approvals and requested rate orders; no significant
operational disruptions or environmental liability due to a catastrophic event
or environmental upset caused by severe weather, other acts of nature or other
major event; the continued ability to maintain the gas and electricity systems
to ensure their continued performance; no significant decline in capital
spending in 2010; no severe and prolonged downturn in economic conditions;
sufficient liquidity and capital resources; the continuation of
regulator-approved mechanisms to flow through the commodity cost of natural gas
and energy supply costs in customer rates; the continued ability to hedge
exposures to fluctuations in interest rates, foreign exchange rates and natural
gas commodity prices; no significant variability in interest rates; no
significant counterparty defaults; the continued competitiveness of natural gas
pricing when compared with electricity and other alternative sources of energy;
the continued availability of natural gas supply; the continued ability to fund
defined benefit pension plans; the absence of significant changes in government
energy plans and environmental laws that may materially affect the operations
and cash flows of the Corporation and its subsidiaries; maintenance of adequate
insurance coverage; the ability to obtain and maintain licences and permits;
retention of existing service areas; no material decrease in market energy sales
prices; maintenance of information technology infrastructure; favourable
relations with First Nations; favourable labour relations; and sufficient human
resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Factors which
could cause results or events to differ from current expectations include, but
are not limited to: regulatory risk; operating and maintenance risks; economic
conditions; capital resources and liquidity risk; weather and seasonality;
commodity price risk; derivative financial instruments and hedging; interest
rate risk; counterparty risk; competitiveness of natural gas; natural gas
supply; defined benefit pension plan performance and funding requirements; risks
related to the development of the Terasen Gas (Vancouver Island) Inc. franchise;
the Government of British Columbia's Energy Plan; environmental risks; insurance
coverage risk; loss of licences and permits; loss of service area; market energy
sales prices; changes in the current assumptions and expectations associated
with the transition to International Financial Reporting Standards; changes in
tax legislation; information technology infrastructure; an ultimate resolution
of the expropriation of the assets of the Exploits Partnership that differs from
what is currently expected by management; an unexpected outcome of legal
proceedings currently against the Corporation; relation with First Nations;
labour relations; and human resources. For additional information with respect
to the Corporation's risk factors, reference should be made to the Corporation's
continuous disclosure materials filed from time to time with Canadian securities
regulatory authorities and to the heading "Business Risk Management" in the MD&A
for the three and six months ended June 30, 2010 and for the year ended December
31, 2009.
All forward-looking information in the MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, the Corporation
undertakes no obligation to revise or update any forward-looking information as
a result of new information, future events or otherwise after the date hereof.
COMPANY OVERVIEW AND FINANCIAL HIGHLIGHTS
Fortis is the largest investor-owned distribution utility in Canada, serving
approximately 2,100,000 gas and electricity customers. Its regulated holdings
include electric utilities in five Canadian provinces and three Caribbean
countries and a natural gas utility in British Columbia. Fortis owns and
operates non-regulated generation assets across Canada and in Belize and Upper
New York State, and hotels and commercial office and retail space primarily in
Atlantic Canada. Year-to-date June 30, 2010, the Corporation's electricity
distribution systems met a combined peak demand of approximately 5,033 megawatts
("MW") and its gas distribution system met a peak day demand of 1,006
terajoules. For additional information on the Corporation's business segments,
refer to Note 1 to the Corporation's 2009 annual audited consolidated financial
statements.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably to customers at the lowest reasonable cost and conduct business in an
environmentally responsible manner. The Corporation's main business, utility
operations, is highly regulated. It is segmented by franchise area and,
depending on regulatory requirements, by the nature of the assets.
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. Key financial highlights, including
earnings by reportable segment, for the second quarter and year-to-date periods
ended June 30, 2010 and June 30, 2009 are provided in the following tables.
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
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Revenue ($ millions) 836 756 80 1,912 1,958 (46)
Cash Flow from
Operating Activities
($ millions) 204 275 (71) 453 504 (51)
Net Earnings
Attributable to
Common Equity
Shareholders ($
millions) 55 53 2 155 145 10
Basic Earnings per
Common Share ($) 0.32 0.31 0.01 0.90 0.85 0.05
Diluted Earnings per
Common Share ($) 0.32 0.31 0.01 0.88 0.83 0.05
Weighted Average
Number of Common
Shares Outstanding
(millions) 172.4 170.0 2.4 172.0 169.7 2.3
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Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
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Regulated Gas
Utilities - Canadian
Terasen Gas
Companies (1) 17 14 3 90 72 18
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Regulated Electric
Utilities - Canadian
FortisAlberta 17 17 - 32 30 2
FortisBC (2) 8 7 1 22 21 1
Newfoundland Power 11 11 - 18 17 1
Other Canadian (3) 4 4 - 9 9 -
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40 39 1 81 77 4
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Regulated Electric -
Caribbean (4) 7 7 - 11 13 (2)
Non-Regulated - Fortis
Generation (5) 3 3 - 5 9 (4)
Non-Regulated - Fortis
Properties (6) 8 8 - 10 10 -
Corporate and Other
(7) (20) (18) (2) (42) (36) (6)
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Net Earnings
Attributable to
Common Equity
Shareholders 55 53 2 155 145 10
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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 mainly
includes Canadian Niagara Power, Cornwall Electric and, from October 2009,
Algoma Power Inc. ("Algoma Power")
(4)Includes Belize Electricity, in which Fortis holds an approximate 70
per cent controlling interest; Caribbean Utilities on Grand Cayman, Cayman
Islands, in which Fortis holds an approximate 59 per cent controlling
interest; and wholly owned Fortis Turks and Caicos
(5)Includes the financial results of non-regulated generating assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New York
State, with a combined generating capacity of 139 megawatts ("MW"), mainly
hydroelectric. Prior to May 1, 2009, the financial results of Fortis
reflected earnings' contribution associated with the Corporation's 75-MW
water-right entitlement on the Niagara River in Ontario related to the
Rankine hydroelectric generating facility. The water rights expired on
April 30, 2009, at the end of a 100-year term. Additionally, prior to
February 12, 2009, the financial results of the hydroelectric generation
operations in central Newfoundland were consolidated in the financial
statements of Fortis. Effective February 12, 2009, the Corporation
discontinued the consolidation method of accounting for the generation
operations in central Newfoundland due to the Corporation no longer having
control over the operations and cash flows, as a result of the
expropriation of the assets of the Exploits River Hydro Partnership by the
Government of Newfoundland and Labrador. For a further discussion of this
matter, refer to the "Critical Accounting Estimates - Contingencies"
section of the MD&A for the year ended December 31, 2009.
(6)Fortis Properties owns and operates 21 hotels, comprised of more than
4,100 rooms, in eight Canadian provinces and approximately 2.8 million
square feet of commercial office and retail space primarily in Atlantic
Canada.
(7)Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. ("Terasen") corporate-related activities and the financial
results of Terasen's 30 per cent ownership interest in CustomerWorks
Limited Partnership ("CWLP") and of Terasen's non-regulated wholly owned
subsidiary Terasen Energy Services Inc. ("TES")
SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
TERASEN GAS COMPANIES
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Gas Volumes by Major Customer Category (Unaudited)
Periods Ended June 30 Quarter Year-to-date
(Terajoules) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Core - Residential and
Commercial 23,827 20,075 3,752 64,258 70,487 (6,229)
Industrial 1,193 1,307 (114) 2,868 3,617 (749)
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Total Sales Volumes 25,020 21,382 3,638 67,126 74,104 (6,978)
Transportation Volumes 14,170 12,485 1,685 30,580 32,734 (2,154)
Throughput under Fixed
Revenue Contracts 3,458 2,584 874 8,126 7,583 543
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Total Gas Volumes 42,648 36,451 6,197 105,832 114,421 (8,589)
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Factors Contributing to Net Positive Quarterly
Gas Volumes Variance
Favourable
-- Higher average consumption by residential and commercial customers as a
result of cooler weather
-- Higher transportation volumes as a result of cooler weather and the
favourable impact of improving economic conditions in the second quarter
of 2010 on the forestry sector
Factors Contributing to Net Negative Year-to-Date
Gas Volumes Variance
Unfavourable
-- Lower average consumption by residential and commercial customers as a
result of warmer weather during the first quarter of 2010, partially
offset by the impact of cooler weather during the second quarter of 2010
-- Lower transportation volumes as a result of warmer weather during the
first quarter of 2010, partially offset by the impact of cooler weather
during the second quarter of 2010 and the impact of unfavourable
economic conditions negatively affecting the forestry sector year-to-
date
Net customer additions were 1,829 during the first half of 2010 compared to
1,068 during the first half of 2009. Gross customer additions increased period
over period due to increased building activity, while customer disconnections
were lower period over period due to cooler weather. Growth in multi-family
housing, however, where natural gas use is less prevalent compared to
single-family housing, has tempered customer growth period over period.
Because of natural gas consumption patterns, earnings of the Terasen Gas
companies are highest in the first and fourth quarters. As a result of
seasonality, interim earnings are not indicative of annual earnings.
The Terasen Gas companies earn approximately the same margin regardless of
whether a customer contracts for the purchase of natural gas or for the
transportation only of natural gas.
As a result of the operation of regulator-approved deferral mechanisms, changes
in consumption levels and energy supply costs from those forecasted to set gas
rates do not materially affect earnings.
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Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
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Revenue 337 289 48 866 958 (92)
Energy Supply Costs 191 156 35 496 624 (128)
Operating Expenses 65 62 3 135 129 6
Amortization 29 26 3 59 51 8
Finance Charges 29 29 - 56 61 (5)
Corporate Taxes 6 2 4 30 21 9
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Earnings 17 14 3 90 72 18
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Factors Contributing to Positive Quarterly Revenue Variance
Favourable
-- Higher average gas consumption per customer
-- Higher commodity cost of natural gas charged to customers
-- Increased customer delivery rates, effective January 1, 2010, which
included the impact of the increase in the allowed rate of return on
common shareholder's equity ("ROE") to 9.50 per cent from 8.47 per cent
for Terasen Gas Inc. ("TGI") and to 10.00 per cent from 9.17 per cent
for Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas
Whistler Inc. ("TGWI"), and the increase in the deemed common equity
component of the total capital structure ("equity component") for TGI to
40 per cent from 35 per cent
Factors Contributing to Net Negative Year-to-Date Revenue Variance
Unfavourable
-- Lower average gas consumption per customer
-- Lower commodity cost of natural gas charged to customers
Favourable
-- The increase in customer delivery rates, effective January 1, 2010, as
discussed above for the quarter
Factors Contributing to Net Positive Quarterly Earnings Variance
Favourable
-- The increase in customer delivery rates, effective January 1, 2010, as
discussed above
Unfavourable
-- Higher operating expenses driven by: (i) increased labour and employee-
benefit costs; (ii) the expensing of asset removal costs to operating
expenses, effective January 1, 2010, as a result of regulator-approved
Negotiated Settlement Agreements ("NSAs") related to 2010 and 2011
revenue requirements; and (iii) lower capitalized overhead costs, due to
a reduction in the capitalization rate, also as a result of the NSAs.
The asset removal costs and expensed overhead costs are being collected
in current customer delivery rates. Prior to 2010, asset removal costs
were recorded against accumulated amortization.
-- Increased amortization cost due to higher amortization rates period over
period and the amortization of contributions in aid of construction
("CIACs") to revenue, beginning January 1, 2010, compared to the
amortization of CIACs against amortization cost in prior periods, as a
result of the NSAs. The new depreciation rates were determined and
approved by the regulator upon review of a current depreciation study.
The increase in amortization is being collected in current customer
delivery rates.
-- A lower effective corporate income tax rate in 2009, primarily due to
higher deductions taken for tax purposes compared to accounting purposes
Factors Contributing to Net Positive Year-to-Date Earnings Variance
Favourable
-- The increase in customer delivery rates, effective January 1, 2010, as
discussed above
-- Lower finance charges, as reflected in current customer delivery rates,
due to lower average credit facility borrowings period over period
Unfavourable
-- The same factors as discussed above for the quarter
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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Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
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Energy Deliveries
(gigawatt hours
("GWh")) 3,724 3,765 (41) 7,833 7,917 (84)
--------------------------------------------------------------------------
($ millions)
Revenue 92 81 11 180 161 19
Operating Expenses 36 31 5 71 65 6
Amortization 25 23 2 49 45 4
Finance Charges 14 13 1 28 24 4
Corporate Tax Recovery - (3) 3 - (3) 3
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Earnings 17 17 - 32 30 2
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Factors Contributing to Net Negative Quarterly
Energy Deliveries Variance
Unfavourable
-- Decreased energy deliveries to residential, farm and irrigation
customers, mainly due to lower average consumption resulting from
relatively milder temperatures, were partially offset by increased
energy deliveries to commercial and other industrial customers. Energy
deliveries to irrigation customers were also negatively impacted by
heavy rainfall during the second quarter of 2010.
Favourable
-- Customer growth with the total number of customers increasing by
approximately 20,000 quarter over quarter
Factors Contributing to Net Negative Year-to-Date
Energy Deliveries Variance
Unfavourable
-- Decreased energy deliveries to residential, farm and irrigation, and
other industrial customers, due to the same reasons as discussed above
for the quarter, were partially offset by increased energy deliveries to
commercial and oil and gas customers.
Favourable
-- Customer growth as discussed above for the quarter
As a significant portion of FortisAlberta's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue.
Factors Contributing to Net Positive Quarterly and Year-to-Date
Revenue Variance
Favourable
-- An interim 7.5 per cent average increase in base customer electricity
distribution rates, effective January 1, 2010, combined with a rate
revenue accrual for the second quarter and first half of 2010 for future
collection from customers relating to certain approved deferral account
items. Approval of FortisAlberta's 2010 and 2011 revenue requirements
was received in July 2010, the effects of which are expected to be
reflected in the third quarter of 2010.
-- A rate revenue accrual of approximately $1 million and $2 million for
the second quarter and first half of 2010, respectively, to reflect an
allowed ROE of 9.00 per cent, compared to an interim allowed ROE of 8.51
per cent as reflected in revenue during the first half of 2009, and an
increase in the equity component to 41 per cent from 37 per cent as
reflected in revenue during the first half of 2009
-- Customer growth
-- Higher franchise fee revenue
-- Higher miscellaneous revenue for the quarter
Unfavourable
-- Lower net transmission revenue
Factors Contributing to Net Positive Quarterly and Year-to-date
Earnings Variance
Favourable
-- The increase in customer electricity distribution rate revenue, for the
reasons discussed above
Unfavourable
-- Increased operating expenses, mainly due to higher labour costs and
general operating expenses, partially offset by lower contracted labour
costs
-- Increased amortization cost associated with continued investment in
utility capital assets, partially offset by the impact of the
commencement in 2010 of the capitalization of amortization for vehicles
and tools used in the construction of other assets, as approved by the
regulator
-- Increased finance charges, due to higher debt levels in support of the
Company's significant capital expenditure program, partially offset by
the impact of lower interest rates on lower average credit facility
borrowings
-- Lower net transmission revenue
-- Lower corporate tax recovery, due to a favourable adjustment to current
income taxes of approximately $2 million during the second quarter of
last year, combined with lower future income tax recoveries associated
with changes in net customer deferrals subject to future income tax
recoveries
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisAlberta, refer to the "Regulatory
Highlights" section of this MD&A.
FORTISBC
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
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Electricity Sales
(GWh) 670 675 (5) 1,490 1,578 (88)
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($ millions)
Revenue 59 55 4 131 127 4
Energy Supply Costs 13 13 - 34 35 (1)
Operating Expenses 19 17 2 36 34 2
Amortization 11 9 2 21 19 2
Finance Charges 8 8 - 16 15 1
Corporate Taxes - 1 (1) 2 3 (1)
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Earnings 8 7 1 22 21 1
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Factors Contributing to Net Negative Quarterly
Electricity Sales Variance
Unfavourable
-- Lower average consumption due to cooler temperatures in June 2010 which
decreased air-conditioning load
Favourable
-- Residential and general service customer growth
-- Increased industrial customer loads
Factors Contributing to Net Negative Year-to-Date
Electricity Sales Variance
Unfavourable
-- The same factor as discussed above for the quarter, combined with lower
average consumption in the first quarter of 2010, due to warmer
temperatures experienced during the first quarter of 2010 compared to
cooler temperatures experienced during the first quarter of 2009
Favourable
-- The same factors as discussed above for the quarter
Factors Contributing to Net Positive Quarterly and Year-to-Date
Revenue Variance
Favourable
-- A 6.0 per cent increase in customer electricity rates, effective January
1, 2010, reflecting an increase in the allowed ROE to 9.90 per cent for
2010, up from 8.87 per cent for 2009, and ongoing investment in
electrical infrastructure
-- Increased performance-based rate-setting ("PBR") incentive adjustments
receivable from customers and higher pole-attachment revenue
-- Higher revenue contribution from non-regulated operating, maintenance
and management services
Unfavourable
-- The 0.7 per cent and 5.6 per cent decrease in electricity sales for the
quarter and year-to-date, respectively, compared to the same periods
last year.
Factors Contributing to Net Positive Quarterly Earnings Variance
Favourable
-- The 6.0 per cent increase in customer electricity rates, effective
January 1, 2010
-- Increased PBR incentive adjustments and pole-attachment revenue, as
discussed above
Unfavourable
-- Higher operating expenses, due to the timing of operating and
maintenance projects in 2010 and their related expenditures, combined
with increased property taxes and water fees
-- Increased amortization cost associated with continued investment in
utility capital assets
-- Decreased electricity sales
Factors Contributing to Net Positive Year-to-Date Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
-- Lower energy supply costs associated with decreased electricity sales
and a lower proportion of purchased power versus energy generated from
Company-owned hydroelectric generating facilities, partially offset by
the impact of higher average prices for purchased power
Unfavourable
-- Increased property taxes and water fees, partially offset by a decrease
in certain other operating expenses due to the timing of operating and
maintenance projects in 2010 and their related expenditures
-- Increased amortization cost, for the same reason as discussed above for
the quarter
-- Higher finance charges, due to higher debt levels in support of the
Company's capital expenditure program, and higher fees and interest
rates on credit facility borrowings
-- Decreased electricity sales
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
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales (GWh) 1,220 1,177 43 3,015 2,940 75
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($ millions)
Revenue 126 119 7 304 288 16
Energy Supply Costs 75 70 5 206 197 9
Operating Expenses 15 13 2 31 27 4
Amortization 12 11 1 23 22 1
Finance Charges 9 9 - 18 17 1
Corporate Taxes 4 5 (1) 8 8 -
--------------------------------------------------------------------------
Earnings 11 11 - 18 17 1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Positive Quarterly and Year-to-Date
Electricity Sales Variance
Favourable
-- Customer growth and higher average consumption
Factors Contributing to Net Positive Quarterly and Year-to-Date
Revenue Variance
Favourable
-- An average 3.5 per cent increase in customer electricity rates,
effective January 1, 2010, reflecting an increase in the allowed ROE to
9.00 per cent for 2010, up from 8.95 per cent for 2009, and higher rate
base and operating expenses, including pension costs
-- A 3.7 per cent and 2.6 per cent increase in electricity sales for the
quarter and year to date, respectively, compared to the same periods
last year
Unfavourable
-- Revenue during the second quarter of 2009 included a gain on sale of
property
Factors Contributing to Net Positive Quarterly and Year-to-Date
Earnings Variance
Favourable
-- The average 3.5 per cent increase in customer electricity rates,
effective January 1, 2010
-- Increased electricity sales
-- Lower than expected operating labour costs due to the timing of capital
projects. Good weather conditions during the first half of 2010 allowed
for an early start to capital projects and there was also an increase in
capital work associated with an ice storm in March 2010.
-- A lower effective corporate income tax rate primarily due to a reduction
in the statutory tax rate and an increase in deductions taken for tax
purposes compared to accounting purposes
Unfavourable
-- Higher pension costs, wage and inflationary cost increases and increased
conservation costs
-- Higher retirement and severance expenses year to date
-- Increased amortization cost associated with continued investment in
utility capital assets
-- Higher finance charges year to date associated with interest expense on
the $65 million 6.606% bonds issued in May 2009, partially offset by the
impact of lower average credit facility borrowings
-- The gain on sale of property during the second quarter of 2009
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Newfoundland Power, refer to the "Regulatory
Highlights" section of this MD&A.
OTHER CANADIAN ELECTRIC UTILITIES
--------------------------------------------------------------------------
Financial Highlights (Unaudited)(1)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales (GWh) 535 483 52 1,167 1,099 68
--------------------------------------------------------------------------
($ millions)
Revenue 75 65 10 157 136 21
Energy Supply Costs 46 40 6 99 87 12
Operating Expenses 11 9 2 22 17 5
Amortization 6 5 1 11 9 2
Finance Charges 5 4 1 11 9 2
Corporate Taxes 3 3 - 5 5 -
--------------------------------------------------------------------------
Earnings 4 4 - 9 9 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Includes Maritime Electric and FortisOntario. FortisOntario includes
financial results of Algoma Power from October 8, 2009, the date of
acquisition.
Factors Contributing to Positive Quarterly
Electricity Sales Variance
Favourable
-- Electricity sales at Algoma Power Inc. ("Algoma Power") of 38 gigawatt
hours ("GWh") during the second quarter of 2010. Algoma Power was
acquired by FortisOntario in October 2009. Excluding electricity sales
at Algoma Power, electricity sales increased 2.9 per cent quarter over
quarter
-- Higher average consumption due to warmer weather conditions experienced
in Ontario
Factors Contributing to Net Positive Year-to-date
Electricity Sales Variance
Favourable
-- Electricity sales at Algoma Power of 92 GWh during the first half of
2010. Excluding electricity sales at Algoma Power, electricity sales
decreased 2.2 per cent period over period
Unfavourable
-- Lower average consumption, due to more moderate temperatures experienced
on Prince Edward Island and in Ontario during the first quarter of 2010,
combined with the impact of conservation initiatives and the economic
downturn, partially offset by higher average consumption in Ontario
during the second quarter of 2010 for the reason discussed above for the
quarter.
Factors Contributing to Positive Quarterly Revenue Variance
Favourable
-- Revenue contribution of approximately $9 million from Algoma Power
during the second quarter of 2010
-- The 2.9 per cent increase in electricity sales, excluding electricity
sales at Algoma Power
Factors Contributing to Net Positive Year-to-Date Revenue Variance
Favourable
-- Revenue contribution of approximately $19 million from Algoma Power
during the first half of 2010
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- An average 5.3 per cent increase in customer electricity rates at
Maritime Electric, effective April 1, 2009, which reflects an increase
in the base amount of energy-related costs being expensed and collected
from customers and recorded in revenue through the basic rate component
of customer billings
-- The increases in the base component of customer electricity distribution
rates at Fort Erie, Gananoque and Port Colborne in Ontario effective May
1, 2009 and May 1, 2010
Unfavourable
-- The 2.2 per cent decrease in electricity sales, excluding electricity
sales at Algoma Power
Factors Contributing to Quarterly and Year-to-Date Earnings Variance
Favourable
-- Algoma Power contributed less than $0.1 million to earnings for the
second quarter of 2010 and approximately $0.5 million to earnings for
the first half of 2010.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Maritime Electric and FortisOntario, refer to the
"Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CARIBBEAN
--------------------------------------------------------------------------
Financial Highlights (Unaudited)(1)
Periods Ended June 30 Quarter Year-to-date
2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.03 1.17 (0.14) 1.03 1.20 (0.17)
Electricity Sales
(GWh) 307 290 17 563 537 26
--------------------------------------------------------------------------
($ millions)
Revenue 83 82 1 159 165 (6)
Energy Supply Costs 47 44 3 92 90 2
Operating Expenses 11 14 (3) 23 28 (5)
Amortization 9 10 (1) 18 20 (2)
Finance Charges 4 4 - 9 8 1
Corporate Taxes 2 - 2 2 1 1
----------------------------------------------------
10 10 - 15 18 (3)
Non-Controlling
Interests 3 3 - 4 5 (1)
--------------------------------------------------------------------------
Earnings 7 7 - 11 13 (2)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2)The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00=US$1.00. The reporting
currency of Caribbean Utilities and Fortis Turks and Caicos is the US
dollar.
Factors Contributing to Positive Quarterly and Year-to-Date
Electricity Sales Variance
Favourable
-- Warmer weather conditions experienced in the region, which increased
air-conditioning load
-- Overall customer growth for the segment, including a new system-
connected medical facility and condominium complex in the Turks and
Caicos Islands
-- Improving tourism activity in the Turks and Caicos Islands which is
favourably impacting large hotel electricity sales
-- In June 2010, Caribbean Utilities and Fortis Turks and Caicos achieved
new record peak loads of 102 MW and 30 MW, respectively
Factors Contributing to Net Positive Quarterly Revenue Variance
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the cost of fuel
-- A 5.9 per cent increase in electricity sales
-- A 2.4 per cent increase in basic customer electricity rates at Caribbean
Utilities, effective June 1, 2009
Unfavourable
-- Approximately $9 million unfavourable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar period over
period
Factors Contributing to Net Negative Year-to-Date Revenue Variance
Unfavourable
-- Approximately $24 million associated with unfavourable foreign currency
translation
-- Revenue during the first quarter of 2009 included approximately $1
million associated with a favourable appeal judgment at Fortis Turks and
Caicos related to a customer rate classification matter.
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, for the reason discussed above for the
quarter
-- The 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
-- A 4.8 per cent increase in electricity sales
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Increased electricity sales
-- The 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
Unfavourable
-- Approximately $1 million associated with unfavourable foreign currency
translation
-- Higher corporate tax expense at Belize Electricity, due to an increase
in the business tax rate to 6.5 per cent from 1.75 per cent, effective
April 1, 2010
-- Higher finance charges, excluding the impact of foreign exchange, mainly
associated with interest expense on the US$40 million 7.5% unsecured
notes issued in May and July 2009 at Caribbean Utilities, and lower
capitalized allowance for funds using during construction
Factors Contributing to Net Negative Year-to-Date Earnings Variance
Unfavourable
-- Approximately $2 million associated with unfavourable foreign currency
translation
-- Higher corporate tax expense at Belize Electricity, for the reason
discussed above for the quarter
-- Higher finance charges, for the reasons discussed above for the quarter,
combined with higher interest expense on regulatory liabilities at
Belize Electricity
-- The favourable impact on energy supply costs during the first quarter of
2009, due to a change in the methodology for calculating the cost of
fuel recoverable from customers at Fortis Turks and Caicos
-- Revenue during the first quarter of 2009 included approximately $1
million associated with the favourable appeal judgment at Fortis Turks
and Caicos.
Favourable
-- Increased electricity sales
-- The 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
-- Lower operating expenses, excluding the impact of foreign exchange, due
to higher capitalized general and administrative expenses and efforts to
control discretionary costs at Caribbean Utilities, partially offset by
increased legal, employee and contractor costs at Belize Electricity
For additional information on the nature of regulation and material regulatory
decisions and applications pertaining to Belize Electricity, Caribbean Utilities
and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of
this MD&A.
NON-REGULATED - FORTIS GENERATION
--------------------------------------------------------------------------
Financial Highlights (Unaudited)(1)
Periods Ended June 30 Quarter Year-to-date
2010 2009(2) Variance 2010 2009(2) Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Sales (GWh) 90 141 (51) 154 398 (244)
--------------------------------------------------------------------------
($ millions)
Revenue 8 9 (1) 13 25 (12)
Energy Supply Costs 1 1 - 1 2 (1)
Operating Expenses 2 2 - 4 6 (2)
Amortization 1 2 (1) 2 4 (2)
Finance Charges - 1 (1) - 2 (2)
Corporate Taxes 1 - 1 1 2 (1)
--------------------------------------------------------------------------
Earnings 3 3 - 5 9 (4)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes the results of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York State
(2)Results reflect contribution from the Rankine hydroelectric generating
facility in Ontario until April 30, 2009. On April 30, 2009, the Rankine
water rights expired at the end of a 100-year term.
Factors Contributing to Net Negative Quarterly and Year-to-Date
Energy Sales Variance
Unfavourable
-- The expiration on April 30, 2009 of the water rights of the Rankine
hydroelectric generating facility in Ontario. Energy sales for the
second quarter and first half of 2009 included approximately 54 GWh and
215 GWh, respectively, related to Rankine.
-- Lower production in Upper New York State due to lower rainfall
-- Lower energy sales year to date related to central Newfoundland
operations. Energy sales for the first quarter of 2009 included 19 GWh
related to central Newfoundland operations up until February 12, 2009,
at which point the consolidation method of accounting for these
operations was discontinued necessitated by the actions of the
Government of Newfoundland and Labrador related to expropriation of the
assets of the Exploits River Hydro Partnership (the "Exploits
Partnership").
Favourable
-- The new Vaca hydroelectric generating facility was commissioned in March
2010. The facility is expected to increase average annual energy
production from the Macal River in Belize by approximately 80 GWh.
Production by the facility was 16 GWh and 20 GWh for the second quarter
and first half of 2010, respectively. Production in Belize, however, was
tempered by the impact of low rainfall earlier in 2010.
Factors Contributing to Net Negative Quarterly and Year-to-Date
Revenue Variance
Unfavourable
-- The loss of revenue subsequent to the expiration of the Rankine water
rights in April 2009
-- The discontinuance of the consolidation method of accounting for the
financial results of the Exploits Partnership in 2009 and timing
differences related to the change in the method of accounting for the
Exploits Partnership
-- Approximately $1 million and $2 million unfavourable foreign exchange
for the quarter and year to date period, respectively, associated with
the translation of US dollar-denominated revenue, due to the weakening
of the US dollar relative to the Canadian dollar compared to the same
periods last year
Favourable
-- Higher production in Belize, for the reason discussed above for the
quarter
Factors Contributing to Net Negative Quarterly and Year-to-Date
Earnings Variance
Unfavourable
-- The expiration of the Rankine water rights. Earnings' contribution
associated with the Rankine hydroelectric generating facility was
approximately $0.2 million for the second quarter of 2009 and $3.5
million for the first half of 2009.
-- Approximately $1 million for each of the quarter and year to date period
associated with unfavourable foreign currency translation
-- Timing differences related to the change in the method of accounting for
the Exploits Partnership in 2009
Favourable
-- Higher production in Belize
-- Reduced finance charges, excluding the impact of foreign exchange, as a
result of higher interest revenue associated with inter-company lending
to regulated operations in Ontario, partially offset by higher interest
expense associated with inter-company lending to finance the
construction of the Vaca hydroelectric generating facility. Coincident
with the commissioning of the facility in March 2010, capitalization of
interest expense during construction ended.
NON-REGULATED - FORTIS PROPERTIES
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Hospitality Revenue 44 42 2 76 73 3
Real Estate Revenue 16 16 - 33 32 1
--------------------------------------------------------------------------
Total Revenue 60 58 2 109 105 4
Operating Expenses 39 38 1 75 72 3
Amortization 4 4 - 8 8 -
Finance Charges 6 5 1 12 11 1
Corporate Taxes 3 3 - 4 4 -
--------------------------------------------------------------------------
Earnings 8 8 - 10 10 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Net Positive Quarterly Revenue Variance
Favourable
-- Overall higher revenue contribution from hotel properties in Atlantic
and central Canada, partially offset by overall lower revenue
contribution from hotel properties in western Canada
-- Revenue growth at the Newfoundland and Nova Scotia regions of the Real
Estate Division, mainly due to rent increases and higher operating
expense recoveries, tempered by revenue decreases in New Brunswick and
Saskatchewan
-- A 0.8 per cent increase in revenue per available room ("RevPAR") at the
Hospitality Division to $83.77 for the second quarter of 2010 from
$83.15 for the same quarter in 2009. RevPAR increased due to an overall
2.6 per cent increase in average room rates, partially offset by an
overall 1.8 per cent decrease in hotel occupancy, mainly at operations
in western Canada. Average room rates at operations in western and
Atlantic Canada increased, while rates at operations in central Canada
decreased.
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division to 94.8 per
cent as at June 30, 2010 from 95.9 per cent as at June 30, 2009
Factors Contributing to Net Positive Year-to-Date Revenue Variance
Favourable
-- Revenue contribution from the Holiday Inn Select Windsor, acquired in
April 2009, combined with overall higher revenue contribution from hotel
properties in Atlantic and central Canada, partially offset by overall
lower revenue contribution from hotel properties in western Canada
-- Revenue growth at the Newfoundland and Nova Scotia regions of the Real
Estate Division, mainly due to rent increases and higher operating
expense recoveries
-- A $0.2 million gain on sale of land in central Newfoundland during the
first quarter of 2010
Unfavourable
-- A 0.8 per cent decrease in RevPAR at the Hospitality Division to $73.45
for the first half of 2010 from $74.03 for the first half of 2009.
RevPAR decreased due to an overall 3.0 per cent decrease in hotel
occupancy, mainly at operations in western Canada, partially offset by
an overall 2.3 per cent increase in average room rates. Average room
rates at operations in western and Atlantic Canada increased, while
rates at operations in central Canada decreased.
Factors Contributing to Quarterly Earnings Variance
-- Improved performance at the Real Estate Division and improved
performance from hotel operations in Atlantic and central Canada were
mostly offset by the unfavourable impact of lower occupancies at hotel
operations in western Canada, driven by the continued impact of the
economic downturn.
Factors Contributing to Year-to-Date Earnings Variance
-- The same factors as discussed above for the quarter, combined with
contribution from the Holiday Inn Select Windsor from April 2009
CORPORATE AND OTHER
--------------------------------------------------------------------------
Financial Highlights (Unaudited)(1)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 9 7 2 15 13 2
Operating Expenses 6 4 2 10 7 3
Amortization 1 2 (1) 4 5 (1)
Finance Charges (2) 18 18 - 38 37 1
Corporate Tax Recovery (4) (4) - (9) (9) -
----------------------------------------------------
(12) (13) 1 (28) (27) (1)
Preference Share
Dividends 8 5 3 14 9 5
--------------------------------------------------------------------------
Net Corporate and
Other Expenses (20) (18) (2) (42) (36) (6)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen corporate-related activities and the financial results of
Terasen's 30 per cent ownership interest in CWLP and of Terasen's non-
regulated wholly owned subsidiary TES
(2) Includes dividends on preference shares classified as long-term
liabilities
Factors Contributing to Net Negative Quarterly and Year-to-Date
Net Corporate and Other Expenses Variance
Unfavourable
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series H in January 2010. For additional information,
see the "Liquidity and Capital Resources" section of this MD&A.
-- Higher operating expenses primarily due to higher business development
costs, partially offset by higher recovery of costs from subsidiary
companies
-- Higher finance charges, excluding the impact of foreign exchange, driven
by interest expense on the 30-year $200 million 6.51% unsecured
debentures issued in July 2009 and higher average credit facility
borrowings, partially offset by lower interest rates charged on those
credit facility borrowings and the repayment of higher interest-bearing
debt. In April 2010, Terasen redeemed its $125 million 8.0% Capital
Securities with proceeds from borrowings under the Corporation's
committed credit facility.
Favourable
-- Increased revenue due to interest income on higher inter-company lending
to Fortis Properties to finance maturing debt
-- A favourable foreign exchange impact of approximately $1 million and $2
million for the quarter and year to date, respectively, associated with
the translation of US dollar-denominated interest expense, due to the
weakening of the US dollar relative to the Canadian dollar compared to
the same periods last year
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
--------------------------------------------------------------------------
Supportive
Allowed Returns (%) Features
-----------------------------------------
Allowed Future or
Common Historical Test
Regulated Regulatory Equity Year Used to Set
Utility Authority (%) 2008 2009 2010 Customer Rates
--------------------------------------------------------------------------
ROE
------------------------
TGI British 40 (1) 8.62 8.47 9.50 Cost of Service
Columbia (2)/ ("COS")/ROE TGI:
Utilities 9.50 (3) Prior to January
Commission 1, 2010, 50/50
("BCUC") sharing of
earnings above or
below the allowed
ROE under a PBR
mechanism that
expired on
December 31, 2009
TGVI BCUC 40 9.32 9.17 10.00 ROEs established
(2)/ by the BCUC,
10.00 effective July 1,
(3) 2009, as a result
of a cost of
capital decision
in the fourth
quarter of 2009.
Previously, the
allowed ROEs were
set using an
automatic
adjustment
formula tied to
long-term Canada
bond yields.
-----------------
Future Test Year
--------------------------------------------------------------------------
FortisBC BCUC 40 9.02 8.87 9.90 COS/ROE
PBR mechanism for
2009 through
2011: 50/50
sharing of
earnings above or
below the allowed
ROE up to an
achieved ROE that
is 200 basis
points above or
below the allowed
ROE - excess to
deferral account
ROE established
by the BCUC,
effective January
1, 2010, as a
result of a cost
of capital
decision in 2009.
Previously, the
allowed ROE was
set using an
automatic
adjustment
formula tied to
long-term Canada
bond yields.
-----------------
Future Test Year
--------------------------------------------------------------------------
Fortis Alberta 41 (4) 8.75 9.00 9.00 COS/ROE
Alberta Utilities
Commission ROE established
("AUC") by the AUC,
effective January
1, 2009, as a
result of a
generic cost of
capital decision
in the fourth
quarter of 2009.
Previously, the
allowed ROE was
set using an
automatic
adjustment
formula tied to
long-term Canada
bond yields.
-----------------
Future Test Year
--------------------------------------------------------------------------
Newfoundland Newfoundland 45 8.95 8.95 +/- 9.00 +/-COS/ROE
Power and Labrador +/- 50 50 bps 50 bps
Board of bps ROE for 2010
Commissioner established by
s of Public the PUB. Except
Utilities for 2010, the
("PUB") allowed ROE is
set using an
automatic
adjustment
formula tied to
long-term Canada
bond yields.
-----------------
Future Test Year
--------------------------------------------------------------------------
Maritime Island 40 10.00 9.75 9.75 COS/ROE
Electric Regulatory
and Appeals
Commission
("IRAC")
-----------------
Future Test Year
--------------------------------------------------------------------------
FortisOntario Ontario 40 (5) 9.00 8.01 8.01 Canadian Niagara
Energy Board Power - COS/ROE
("OEB")
Canadian
Niagara
Power
Algoma Power 50 N/A 8.57 8.57/ Algoma Power -
Franchise 9.85(6) COS/ROE and
Agreement subject to Rural
Cornwall Rate Protection
Electric Subsidy program
Cornwall Electric
- Price cap with
commodity cost
flow through
-----------------
Canadian Niagara
Power - 2004
historical test
year for 2008;
2009 test year
for 2009 and 2010
Algoma Power -
2007 historical
test year for
2009; 2010 test
year for 2010
--------------------------------------------------------------------------
ROA (7)
------------------------
Belize Public N/A 10.00 10.00 - (8) Four-year COS/
Electricity Utilities ROA agreements
Commission
("PUC") Additional costs
in the event of a
hurricane would
be deferred and
the Company may
apply for future
recovery in
customer rates.
-----------------
Future Test Year
--------------------------------------------------------------------------
Caribbean Electricity N/A 9.00 - 9.00 7.75 - COS/ROA
Utilities Regulatory 11.00 -11.00 9.75
Authority Rate-cap
("ERA") adjustment
mechanism
("RCAM") based on
published
consumer price
indices
Under the new
transmission and
distribution
licence, the
Company may apply
for a special
additional rate
to customers in
the event of a
disaster,
including a
hurricane.
-----------------
Historical Test
Year
--------------------------------------------------------------------------
Fortis Turks Utilities N/A 17.50 17.50 17.50 (9)COS/ROA
and Caicos make annual (9) (9)
filings with If the actual ROA
the is lower than the
Government allowed ROA, due
to additional
costs resulting
from a hurricane
or other event,
the Company may
apply for an
increase in
customer rates in
the following
year.
-----------------
Future Test Year
--------------------------------------------------------------------------
(1)Effective January 1, 2010. For 2008 and 2009, the allowed deemed equity
component of the capital structure was 35 per cent.
(2)Pre-July 1, 2009
(3)Effective July 1, 2009
(4)Effective January 1, 2009. For 2008, the allowed deemed equity
component of the capital structure was 37 per cent.
(5)Effective May 1, 2010. For 2009, effective May 1, the allowed deemed
equity component of the capital structure was 43.3 per cent.
(6)Proposed at 9.85 per cent effective July 1, 2010, subject to regulatory
approval
(7)Rate of return on rate base assets
(8)Allowed ROA to be settled once regulatory matters are resolved
(9)Amount provided under licence. Actual ROAs achieved in 2008 and 2009
were materially lower than the ROA allowed under the licence due to
significant investment occurring at the utility.
Material Regulatory Decisions and Applications
--------------------------------------------------------------------------
Regulated Utility Summary Description
--------------------------------------------------------------------------
TGI/TGVI - TGI and TGVI review with the BCUC natural gas
and propane commodity rates every three months and
mid-stream rates annually in order to ensure the
flow through rates charged to customers are
sufficient to cover the cost of purchasing natural
gas and propane and contracting for mid-stream
resources, such as third-party pipeline or storage
capacity. The commodity cost of natural gas and
mid-stream costs are flowed through to customers
without markup. Effective January 1, 2010, the
BCUC approved an increase in mid-stream rates for
natural gas and kept commodity rates for natural
gas unchanged for customers in the Lower Mainland,
Fraser Valley, Interior, North and the Kootenay
service areas. The BCUC also approved a decrease
in commodity rates for natural gas for customers
in Whistler, effective January 1, 2010. Effective
April 1, 2010, the BCUC approved an increase in
commodity rates for natural gas for customers in
the Lower Mainland, Fraser Valley, Interior, North
and the Kootenay service areas, while rates for
natural gas customers on Vancouver Island and in
Whistler and Fort Nelson remained unchanged.
Effective July 1, 2010, the BCUC approved
decreases in commodity rates for natural gas and
propane customers in the Lower Mainland, Fraser
Valley, Interior, North and the Kootenay service
areas while rates for natural gas customers on
Vancouver Island and in Whistler and Fort Nelson
remain unchanged.
- In November and December 2009, the BCUC
approved: (i) NSAs pertaining to the 2010 and 2011
Revenue Requirements Applications for TGI and
TGVI; (ii) an increase in TGI's equity component,
effective January 1, 2010, to 40 per cent from 35
per cent; (iii) an increase in TGI's allowed ROE,
effective July 1, 2009, to 9.50 per cent from 8.47
per cent; and (iv) an increase in the allowed ROE
to 10.00 per cent, effective July 1, 2009, from
9.17 per cent for each of TGVI and TGWI. In its
decision on the Return on Equity and Capital
Structure Application, the BCUC maintained TGI as
a benchmark utility for calculating the allowed
ROE for certain utilities regulated by the BCUC.
The BCUC also determined that the former automatic
adjustment formula used to establish the ROE
annually will no longer apply and the allowed ROEs
as determined in the BCUC decision will apply
until reviewed further by the BCUC. The BCUC-
approved NSA for TGI did not include a provision
to allow the continued use of a PBR mechanism
after the expiry, on December 31, 2009, of TGI's
previous PBR agreement. The approved mid-year
rate base at TGI is $2,540 million for 2010 and
$2,634 million for 2011, and the approved mid-year
rate base at TGVI is approximately $555 million
for 2010 and $729 million for 2011. The impact of
the approved NSAs, increase in the allowed ROEs,
and higher equity component at TGI resulted in an
increase in customer rates, effective January 1,
2010. Customer rates for TGVI's sales customers,
however, will remain unchanged for the two-year
period beginning January 1, 2010, as provided in
the BCUC-approved NSA for TGVI.
- In February 2010, the BCUC approved TGI's
application for the in-sourcing of core elements
of its customer care services and implementation
of a new customer information system, upon the
Company accepting a cost risk-sharing condition,
whereby TGI would share equally with customers any
costs or savings outside a band of plus or minus
10 per cent of the approved total project cost of
approximately $116 million, including deferral of
certain operating and maintenance expenses.
--------------------------------------------------------------------------
FortisBC - In December 2009, the BCUC approved an NSA
pertaining to FortisBC's 2010 Revenue Requirements
Application. The result was a general customer
electricity rate increase of 6.0 per cent,
effective January 1, 2010. The rate increase was
primarily the result of the Company's ongoing
investment in infrastructure, increasing energy
supply costs and the higher cost of capital.
FortisBC's allowed ROE has increased to 9.90 per
cent, effective January 1, 2010, from 8.87 per
cent in 2009 as a result of the BCUC decision to
increase the allowed ROE of TGI, the benchmark
utility in British Columbia. The BCUC-approved
NSA assumes a mid-year rate base of approximately
$975 million for 2010.
- In June 2010, FortisBC applied to the BCUC for
approval of the Company's 2011 Capital Expenditure
Plan totalling approximately $114 million, before
customer contributions of approximately $11
million, and including approximately $6 million
associated with Demand Side Management programs.
--------------------------------------------------------------------------
FortisAlberta - In June 2009, FortisAlberta filed a
comprehensive two-year Distribution Tariff
Application ("DTA") for 2010 and 2011. The DTA
forecasts a mid-year rate base of approximately
$1,538 million for 2010 and $1,724 million for
2011. The DTA proposed an average increase in
base customer electricity distribution rates of
13.3 per cent for 2010 and 14.9 per cent for 2011,
before considering the impact of the increase in
the allowed ROE and equity component, as per the
AUC 2009 Generic Cost of Capital Decision (the
"2009 GCOC Decision") as described below. The
proposed rate increases are primarily driven by
the Company's ongoing investment in infrastructure
to support customer growth and maintain and
upgrade the electricity system.
- In December 2009, FortisAlberta provided the AUC
with an update to the proposed forecast revenue
requirements for 2010 and 2011, primarily to
reflect the 2009 GCOC Decision. The 2009 GCOC
Decision established a generic allowed ROE of 9.00
per cent for each of 2009 and 2010 for all Alberta
utilities regulated by the AUC. This allowed ROE
is up from the interim allowed ROE of 8.51 per
cent that was applicable to FortisAlberta in 2009.
The ROE automatic adjustment formula will no
longer apply until reviewed further by the AUC.
The AUC also increased FortisAlberta's equity
component to 41 per cent from 37 per cent,
effective January 1, 2009. The $4.1 million
favourable 2009 annual impact of the 2009 GCOC
Decision was accrued as revenue in the fourth
quarter of 2009 and is expected to be collected in
customer electricity rates in 2011.
- In December 2009, the AUC approved, on an
interim basis, a 7.5 per cent average increase in
FortisAlberta's base customer electricity
distribution rates, effective January 1, 2010. A
decision on the DTA was received in July 2010.
While the decision was largely as anticipated,
approval of the updated forecast of the capital
cost of the automated metering project is pending
negotiation with customer groups. A compliance re-
filing application will be filed by the Company
with the AUC by August 30, 2010 and the impacts of
the decision are expected to be incorporated in
the Company's third quarter financial results.
- The AUC has initiated a process to reform
utility rate regulation in Alberta. The AUC has
expressed its intention to apply a PBR formula to
distribution service rates as early as July 1,
2012. FortisAlberta is currently assessing PBR
and will participate fully in the AUC process.
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Newfoundland - In December 2009, the PUB issued a decision on
Power Newfoundland Power's 2010 General Rate Application
("2010 GRA"), resulting in an overall average
increase in customer electricity rates of
approximately 3.5 per cent, effective January 1,
2010. The rate increase reflects the impact of an
increase in the allowed ROE to 9.00 per cent from
8.95 per cent in 2009, as set by the PUB for 2010,
and higher rate base and operating expenses,
including pension costs. The PUB decision assumes
a mid-year rate base of approximately $869 million
for 2010. The PUB also ordered that Newfoundland
Power's allowed ROE for each of 2011 and 2012 be
determined using the ROE automatic adjustment
formula.
- In April 2010, the PUB approved the Company's
application, as filed, to change the existing ROE
automatic adjustment formula. Consensus Forecasts
will now be used in determining the risk-free rate
for calculating the forecast cost of equity to be
used in the formula for 2011 and 2012. The
previous approach used a ten-day observation of
long-term Canada Bond yields as the forecast risk-
free rate.
- Under the terms of a Joint Use Facilities
Partnership Agreement ("JUFPA") between
Newfoundland Power and Bell Aliant (previously,
Aliant Telecom Inc.), Newfoundland Power received
notice in June 2010 of Bell Aliant's intention to
not renew the JUFPA with Newfoundland Power, which
expires December 31, 2010, and to repurchase 40
per cent of all joint-use poles from Newfoundland
Power for a book-based value. Under the JUFPA,
Newfoundland Power acquired approximately 70,000
joint-use distribution poles from Bell Aliant in
2001 for a book-based value of approximately $40
million. Bell Aliant has been renting space on
these poles from Newfoundland Power since 2001.
Any disposition of joint-use poles back to Bell
Aliant will require regulatory approval. Upon
purchase of the poles, Bell Aliant will also have
the obligation to install and maintain 40 per cent
of the jointly used poles on an ongoing basis.
Once the final terms and conditions have been
negotiated between Newfoundland Power and Bell
Aliant, Newfoundland Power will be able to assess
the impact of the above transaction on its future
results of operations, cash flows and financial
position.
- Newfoundland Power submitted a proposal to the
PUB in June 2010 relating to the accounting for,
and recovery of, other post-employment benefits
("OPEB") costs. The Company recommends that it:
(i) adopt the accrual method of accounting for
OPEB costs effective January 1, 2011; (ii) recover
the transitional balance, or regulatory asset,
associated with adoption of accrual accounting
over a 15-year period; and (iii) adopt a deferral
account to capture differences in OPEB costs
arising from changes in assumptions associated
with the valuation of OPEB obligations. The
regulatory asset was approximately $47 million as
at December 31, 2009. The proposal is currently
under review by the PUB.
- In July 2010, Newfoundland Power filed an
application with the PUB requesting approval for
its 2011 Capital Expenditure Plan totaling
approximately $73 million.
- Effective July 1, 2010, there was an overall
average increase in electricity rates charged to
Newfoundland Power customers of approximately 1.7
per cent. The increase was a result of the normal
annual operation of the Rate Stabilization Plan of
Newfoundland and Labrador Hydro ("Newfoundland
Hydro"). Variances in the cost of fuel used to
generate the electricity that Newfoundland Hydro
sells to Newfoundland Power are captured and
flowed through to Newfoundland Power customers
through the operation of the Rate Stabilization
Plan. The increase in customer rates will have no
impact on earnings of Newfoundland Power.
- Newfoundland Power is currently assessing the
requirement to file an application with the PUB to
recover expected increased costs in 2011.
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Maritime Electric - In July 2010, IRAC approved Maritime Electric's
2010/2011 Rate Application providing for: (i) an
increase in the reference cost of energy in basic
electricity rates, effective August 1, 2010; (ii)
the amortization of the replacement energy costs
incurred during the refurbishment of the New
Brunswick Power Point Lepreau Nuclear Generating
Station ("Point Lepreau") over a period of 25
years, representing the extended life of the unit;
and (iii) an allowed ROE of 9.75 per cent for both
2010 and 2011, unchanged from 2009.
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FortisOntario - In April 2010, FortisOntario received Decisions
and Orders from the OEB with respect to Third-
Generation Incentive Rate Mechanism ("IRM")
electricity distribution rate applications for
harmonized rates for Fort Erie and Gananoque and
rates for Port Colborne, effective May 1, 2010. In
non-rebasing years, customer electricity rates are
set using inflationary factors less an efficiency
target under the OEB's Third-Generation IRM. The
resulting increase in base electricity rates,
effective May 1, 2010, was minimal, with an
inflationary increase of 1.3 per cent partially
offset by a 1.12 per cent efficiency target. The
approved electricity rates were also based on a
deemed capital structure containing 40 per cent
equity and reflect an allowed ROE of 8.01 per
cent.
- In June 2010, FortisOntario filed a new cost of
service electricity distribution rate application
for Algoma Power for rates effective July 1, 2010
and January 1, 2011, based on 2010 and 2011 test
years, respectively. The application proposes an
approximate 14.6 per cent increase in electricity
delivery rates in 2010 and an approximate 7.4 per
cent increase in rates in 2011. The application
is based on a deemed capital structure containing
40 per cent equity and a currently estimated
allowed ROE of 9.85 per cent.
- In the second half of 2010, FortisOntario
expects to file electricity distribution rate
applications for harmonized rates for Fort Erie
and Gananoque and rates for Port Colborne,
effective January 1, 2011, using 2011 as a forward
test year.
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Belize Electricity - Changes made in electricity legislation by the
Government of Belize and the PUC, and the PUC's
June 2008 Final Decision on Belize Electricity's
2008/2009 Rate Application and the PUC's amendment
to the June 2008 Final Decision, which were based
on the changed legislation, have been judicially
challenged by Belize Electricity in several
proceedings. The judicial process is ongoing with
interim rulings, judgments and appeals. The timing
or likely final outcome of the proceedings is
indeterminable at this time. In response to an
application from Belize Electricity, the Supreme
Court of Belize issued an order in June 2010
prohibiting the PUC from carrying out any rate-
setting review proceedings, changing any rates and
taking any enforcement or penal steps against
Belize Electricity until further order of the
Supreme Court.
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Caribbean Utilities - In February 2010, the ERA approved Caribbean
Utilities' 2010-2014 Capital Investment Plan at
US$98 million for non-generation expansion
expenditures. Additional generation needs are
subject to a competitive bid process.
- In May 2010, Caribbean Utilities submitted its
annual RCAM calculations to the ERA as set out in
the utility's transmission and distribution
licence. The RCAM, which permits base electricity
rates to move with inflation, yielded no rate
adjustment that otherwise would have been in
effect as of June 1, 2010, as the slight inflation
in the US price index was offset by deflation in
the Cayman Islands price index for calendar year
2009.
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Fortis Turks and Caicos - In March 2010, Fortis Turks and Caicos submitted
its 2009 annual regulatory filing outlining the
Company's performance in 2009 and its capital
expansion plans for 2010.
- In March 2010, Fortis Turks and Caicos filed an
Electricity Rate Review with the Ministry of
Works, Housing and Utilities of the Government of
the Turks and Caicos Islands in accordance with
Section 34 of the Electricity Ordinance. The
filing requested an average 7 per cent increase in
base customer electricity rates, effective May 31,
2010. The rate increase would have been the first
rate increase implemented by Fortis Turks and
Caicos since its inception. The objectives of the
Electricity Rate Review included setting rates for
the various classes of customers through an
Allocated Cost of Service Study, introducing
uniformity in the rate structure throughout the
service territory of Fortis Turks and Caicos and
enabling the utility to start to recover its
December 31, 2009 accumulated regulatory shortfall
in achieving its allowable profit.
- In June 2010, Fortis Turks and Caicos received
notice from the Governor of the Turks and Caicos
Islands that the Company's Electricity Rate Review
filing was not accepted because of concern of the
impact that the proposed rate increase might have
on key sectors of the Islands' economy. Fortis
Turks and Caicos is continuing discussions with
the Government and has requested the Governor to
appoint an outside, independent consultant to
review the filing and the current rate setting
mechanism and make recommendations regarding both.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between June 30, 2010 and December 31, 2009.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
June 30, 2010 and December 31, 2009
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Balance Increase/
Sheet (Decrease)($
Account millions) Explanation
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Accounts (78) The decrease was primarily due to the impact of a
receivable seasonal decrease in sales, driven by the Terasen
Gas companies.
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Regulatory 69 The increase was driven by deferrals at the
assets - Terasen Gas companies associated with: (i) a $38
current and million change in the fair market value of the
long-term natural gas derivatives; and (ii) the drawdown of
the Commodity Cost Reconciliation Account, as
amounts are being refunded to customers in current
commodity rates, partially offset by a reduction
in the Midstream Cost Reconciliation Account, as
amounts collected in customer rates were in excess
of actual mid-stream gas-delivery costs.
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Inventories (34) The decrease was driven by the normal seasonal
reduction of gas in storage at the Terasen Gas
companies, due to higher consumption during the
winter months.
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Utility 242 The increase primarily related to $413 million
capital invested in electricity and gas systems and the
assets impact of foreign exchange on the translation of
foreign currency-denominated utility capital
assets, partially offset by amortization and
customer contributions for the six months ended
June 30, 2010.
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Short-term (196) The decrease was driven by the repayment of short-
borrowings term borrowings by TGI with proceeds from an
equity injection from Fortis, lower borrowings at
the Terasen Gas companies due to seasonality of
its operations and the reclassification of $70
million borrowed under TGVI's credit facility to
long-term debt upon renegotiation of the Company's
committed credit facility. Partially offsetting
the decrease was higher borrowings at Maritime
Electric, to finance $15 million of maturing long-
term debt, and at Caribbean Utilities, to finance
capital expenditures.
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Accounts (47) The decrease was driven by lower amounts owing for
payable and purchased natural gas at the Terasen Gas companies
accrued and purchased power at Newfoundland Power due to
charges seasonality of operations, partially offset by a
$38 million change in the fair market value of the
natural gas derivatives at the Terasen Gas
companies.
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Dividends 49 The increase was due to the timing of the
payable declaration of common share dividends for the
first quarter of 2010 and an increase in the
quarterly common share dividend declared from
$0.26 per share to $0.28 per share.
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Regulatory 23 The increase was mainly due to an increase in the
liabilities Rate Stabilization Deferral Account at TGVI,
- current reflecting the accumulation of over-recovered
and long- costs of providing service to customers year-to-
term date 2010, partially offset by a reduction in the
Revenue Stabilization Adjustment Mechanism account
at TGI, as natural gas consumption volumes were
lower than forecast during the first half of 2010.
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Long-term 23 The increase was driven by a net $157 million
debt and increase in committed credit facility borrowings
capital classified as long-term, the reclassification of
lease $70 million of committed credit facility
obligations borrowings by TGVI from short-term borrowings and
(including the impact of foreign exchange on the translation
current of foreign currency-denominated long-term debt.
portion) The increase was partially offset by regularly
scheduled debt repayments, including the repayment
of maturing $15 million 12% debentures at Maritime
Electric with proceeds from short-term borrowings,
and the redemption of the $125 million 8.0%
Capital Securities at Terasen with proceeds from
borrowings under the Corporation's committed
credit facility.
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Shareholders 302 The increase was driven by the issuance of $250
' equity million five-year fixed rate reset preference
shares in January 2010. The remainder of the
increase was due to net earnings attributable to
common equity shareholders for the six months
ended June 30, 2010, less common share dividends,
and the issuance of common shares under the
Corporation's share purchase, dividend
reinvestment and stock option plans.
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LIQUIDITY AND CAPITAL RESOURCES
Summary of Consolidated Cash Flows: The table below outlines the Corporation's
consolidated sources and uses of cash for the three and six months ended June
30, 2010, as compared to the same periods in 2009, followed by a discussion of
the nature of the variances in cash flows.
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Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
-------------------------------------------------------------------------
Cash, Beginning of Period 92 94 (2) 85 66 19
Cash Provided by (Used in):
Operating Activities 204 275 (71) 453 504 (51)
Investing Activities (229) (272) 43 (405) (482) 77
Financing Activities 3 41 (38) (62) 50 (112)
Effect of Exchange Rate Changes
on Cash and Cash Equivalents 1 (1) 2 - (1) 1
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Cash, End of Period 71 137 (66) 71 137 (66)
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $71 million lower quarter over quarter driven by
unfavourable working capital changes at the Terasen Gas companies, reflecting
differences in the commodity cost of natural gas and the cost of natural gas
charged to customers period over period and the differing effects of
seasonality.
Cash flow from operating activities, after working capital adjustments, was $51
million lower year to date compared to the same period in 2009, driven by
unfavourable working capital changes partially offset by higher earnings. The
unfavourable working capital changes were driven by the Terasen Gas companies
for the reasons discussed above for the quarter, partially offset by: (i)
favourable changes in the Alberta Electric System Operator ("AESO") charges
deferral account at FortisAlberta; (ii) the timing of property tax and other
payments at FortisBC; (iii) a decrease in the amount of corporate taxes paid at
the Terasen Gas companies and Newfoundland Power; (iv) and the timing of the
declaration of common share dividends for the first quarter of 2010.
Investing Activities: Cash used in investing activities was $43 million lower
quarter over quarter and $77 million lower year to date compared to the same
period in 2009. The decrease was driven by lower gross capital expenditures at
FortisAlberta, mainly due to lower demand for new residential services,
irrigation and farm services and lower spending related to equipment, facilities
and AESO transmission capital projects. Lower gross capital expenditures at the
Regulated Electric Utilities - Caribbean, Fortis Generation and the Terasen Gas
companies were partially offset by higher gross capital expenditures at
FortisBC.
Financing Activities: Cash provided by financing activities was $3 million
during the second quarter of 2010 compared to $41 million during the same
quarter in 2009. Cash used in financing activities was $62 million year to date
compared to cash provided by financing activities of $50 million during the same
period in 2009. Quarter over quarter and year to date compared to the same
period last year, lower proceeds from long-term debt, higher repayments of
long-term debt and higher common and preference share dividends were partially
offset by favourable variances in short-term borrowings, higher proceeds from
net borrowings under committed credit facilities and higher proceeds from the
issuance of common shares. Proceeds from the issuance of preference shares were
also higher year to date compared to the same period in 2009.
Net proceeds from short-term borrowings were $55 million during the second
quarter of 2010 compared to net repayments of short-term borrowings of $89
million during the same quarter in 2009. Net repayments of short-term borrowings
were $126 million year to date compared to $239 million during the same period
in 2009. The changes in short-term borrowings for the second quarter and
year-to-date periods of 2010 were driven by the Terasen Gas companies. In
January 2010, TGI repaid short-term borrowings using proceeds from an equity
injection by the Corporation.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease obligations and net borrowings (repayments) under committed
credit facilities for the quarter and year to date compared to the same periods
last year are summarized in the following tables.
--------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
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Terasen Gas Companies - - - - 99 (1) (99)
FortisAlberta - - - - 99 (2) (99)
FortisBC - 104 (3) (104) - 104 (3) (104)
Newfoundland Power - 65 (4) (65) - 65 (4) (65)
Caribbean Utilities - 34 (5) (34) - 34 (5) (34)
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Total - 203 (203) - 401 (401)
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(1) Issued February 2009, 30-year $100 million 6.55% unsecured debentures by
TGI. The net proceeds were used to repay credit facility borrowings and
repay $60 million 10.75% unsecured debentures that matured in June 2009.
(2) Issued February 2009, 30-year $100 million 7.06% unsecured debentures.
The net proceeds were used to repay committed credit facility borrowings
and for general corporate purposes.
(3) 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 6.75%
debentures that matured in July 2009.
(4) 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.
(5) Issued May 2009, 15-year US$30 million 7.50% unsecured notes. The net
proceeds were used to repay short-term borrowings and finance capital
expenditures.
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Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Terasen Gas companies (1) (63) 62 (1) (63) 62
Maritime Electric (15) - (15) (15) - (15)
Caribbean Utilities (15) (16) 1 (15) (16) 1
Fortis Properties (38) (3) (35) (52) (5) (47)
Corporate - Terasen (125)(1) - (125) (125)(1) - (125)
Other (2) (3) 1 (4) (7) 3
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Total (196) (85) (111) (212) (91) (121)
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(1) In April 2010, Terasen redeemed in full for cash its $125 million
8.0% Capital Securities with proceeds from borrowings under the
Corporation's committed credit facility.
-----------------------------------------------------------------------
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended June 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
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FortisAlberta 20 55 (35) 60 1 59
FortisBC 21 (36) 57 12 (31) 43
Newfoundland Power 2 (57) 59 13 (27) 40
Corporate 143 90 53 72 114 (42)
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Total 186 52 134 157 57 100
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Borrowings under credit facilities by the utilities are primarily in support of
their capital expenditure programs and/or for working capital requirements.
Repayments are primarily financed through the issuance of long-term debt, cash
from operations and/or equity injections from Fortis. From time to time,
proceeds from preference share, common share and long-term debt issues are used
to repay borrowings under the Corporation's committed credit facility.
Proceeds from the issuance of common shares increased $5 million quarter over
quarter and $15 million year to date compared to the same period in 2009,
reflecting the impact of the participation by shareholders in the Corporation's
enhanced Dividend Reinvestment and Share Purchase Plan. The plan provides
participating common shareholders a 2 per cent discount on the purchase of
common shares, issued from treasury, with reinvested dividends.
In January 2010, Fortis completed a $250 million five-year fixed rate reset
preference share offering. The net proceeds of approximately $242 million were
used to repay borrowings under the Corporation's committed credit facility and
to fund an equity injection into TGI.
Common share dividends were $49 million for the second quarter, up $5 million
from the same quarter in 2009, due mainly to an increase in the quarterly common
share dividend declared. Common share dividends were $145 million year to date,
up $57 million from the same period in 2009. The increase was primarily due to
the timing of the declaration of common share dividends for the first quarter of
2010 and an increase in the quarterly common share dividends declared. The
dividend declared per common share in each of the first and second quarters of
2010 was $0.28, while the dividend declared per common share in each of the
first and second quarters of 2009 was $0.26.
Preference share dividends increased $3 million quarter over quarter and $5
million year to date compared to the same period in 2009, as a result of the
dividends associated with the 10 million preference shares that were issued in
January 2010.
Contractual Obligations: Consolidated contractual obligations of Fortis over the
next five years and for periods thereafter, as of June 30, 2010, are outlined in
the following table. A detailed description of the nature of the obligations is
provided below and in the MD&A for the year ended December 31, 2009.
---------------------------------------------------------------------------
Contractual Obligations (Unaudited)
Due Due in Due in Due
within 1 years 2 years 4 after 5
As at June 30, 2010 ($ millions) Total year and 3 and 5 years
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Long-term debt 5,523 156 561 773 4,033
Brilliant Terminal Station 61 3 5 5 48
Gas purchase contract obligations
(1) 620 277 222 121 -
Power purchase obligations
FortisBC (2) 2,917 44 89 82 2,702
FortisOntario 486 47 96 169 174
Maritime Electric 60 41 2 2 15
Belize Electricity 317 29 67 59 162
Capital cost 410 26 33 32 319
Joint-use asset and share service
agreements 61 3 6 6 46
Office lease - FortisBC 18 1 3 3 11
Operating lease obligations 140 17 30 26 67
Equipment purchase - Fortis Turks
and Caicos 5 5 - - -
Defined benefit pension funding
contributions (3) 38 16 16 4 2
Other (4) 22 5 9 6 2
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Total 10,678 670 1,139 1,288 7,581
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(1) Based on index prices as at June 30, 2010
(2) During the first quarter of 2010, FortisBC entered into a contract
with Powerex Corp., a wholly owned subsidiary of BC Hydro, for fixed-
price winter capacity purchases through to February 2016 in an
aggregate amount of approximately US$16 million. If FortisBC brings
any new resources, such as capital or contractual projects, on-line
prior to the expiry of this agreement, FortisBC may terminate this
contract any time after July 1, 2013 with a minimum of three-months'
written notice to Powerex Corp.
(3) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than the above estimated amounts pending completion of the next
actuarial valuations for funding purposes, which are expected to be
performed as of the following dates for the larger defined benefit
pension plans:
December 31, 2009 Terasen (covering non-unionized employees)
December 31, 2010 Terasen (covering unionized employees) and FortisBC
December 31, 2011 Newfoundland Power
(4) Other contractual obligations include capital lease obligations,
operating building leases, and asset retirement obligations at
FortisBC.
Other Contractual Obligations:
In prior years, TGVI received non-interest bearing repayable loans from the
federal and provincial governments of $50 million and $25 million, respectively,
in connection with the construction and operation of the Vancouver Island
natural gas pipeline. As approved by the BCUC, these loans have been recorded as
government grants and have reduced the amounts reported for utility capital
assets. The government loans are repayable in any fiscal year prior to 2012
under certain circumstances and subject to the ability of TGVI to obtain
non-government subordinated debt financing on reasonable commercial terms. As
the loans are repaid and replaced with non-government loans, utility capital
assets and long-term debt will increase in accordance with TGVI's approved
capital structure, as will TGVI's rate base, which is used in determining
customer rates. The repayment criteria were met in 2009 and TGVI made an
approximate $4 million repayment on the loans during the second quarter of 2010.
As at June 30, 2010, the outstanding balance of the repayable government loans
was approximately $49 million, with approximately $4 million classified as
current portion of long-term debt. Repayments of the government loans are not
included in the contractual obligations table above as the amount and timing of
the repayments are dependent upon the ability of TGVI to replace the government
loans with non-government subordinated debt financing on reasonable commercial
terms. TGVI, however, estimates making payments under the loans of $20 million
in 2012, $14 million over 2013 and 2014 and $15 million thereafter.
Caribbean Utilities has a primary fuel supply contract with a major supplier and
is committed to purchase 80 per cent of the Company's fuel requirements from
this supplier for the operation of Caribbean Utilities' diesel-powered
generating plant. The initial contract was for three years and terminated in
April 2010. CUC continues to operate within the terms of the initial contract.
The contract contains an automatic renewal clause for years 2010 through 2012.
Should any party choose to terminate the contract within that two-year period,
notice must be given a minimum of one year in advance of the desired termination
date. No such termination notice has been given by either party to date. As
such, the contract is effectively renewed until 2011. The quantity of fuel to
be purchased under the contract for 2010 is approximately 25 million imperial
gallons.
Fortis Turks and Caicos has a renewable contract with a major supplier for all
of its diesel fuel requirements associated with the generation of electricity.
The approximate fuel requirements under this contract are 12 million imperial
gallons per annum.
Capital Structure: The Corporation's principal businesses of regulated gas and
electricity distribution require ongoing access to capital to allow the
utilities to fund maintenance and expansion of infrastructure. Fortis raises
debt at the subsidiary level to ensure regulatory transparency, tax efficiency
and financing flexibility. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40
per cent equity, including preference shares, and 60 per cent debt, as well as
investment-grade credit ratings. Each of the Corporation's regulated utilities
maintains its own capital structure in line with the deemed capital structure
reflected in the utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
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Capital Structure
(Unaudited) As at
June 30, 2010 December 31, 2009
($ millions) (%)($ millions) (%)
--------------------------------------------------------------------------
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Total debt and capital
lease obligations (net of
cash) (1) 5,671 57.7 5,830 60.2
Preference shares (2) 912 9.3 667 6.9
Common shareholders'
equity 3,248 33.0 3,193 32.9
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Total (3) 9,831 100.0 9,690 100.0
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(1)Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2)Includes preference shares classified as both long-term liabilities and
equity
(3)Excludes amounts related to non-controlling interests
--------------------------------------------------------------------------
The change in the capital structure was driven by the issuance of $250 million
preference shares in January 2010; increased common shares outstanding,
reflecting the impact of the Corporation's enhanced Dividend Reinvestment and
Share Purchase Plan; and the repayment of credit facility borrowings with
proceeds from the preference share issue.
Credit Ratings: The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A-(stable) (long-term corporate and unsecured
debt credit rating)
DBRS BBB(high) (unsecured debt credit rating)
In May 2010, S&P confirmed its existing debt credit rating for Fortis at
A-(stable). In June 2010, DBRS confirmed its existing debt credit rating for
Fortis at BBB(high), but changed the trend to 'Positive' from 'Stable'. The
above credit ratings and recent trend change by DBRS reflect the Corporation's
low business risk profile and diversity of its operations, the stand-alone
nature and financial separation of each of the regulated subsidiaries of Fortis,
management's commitment to maintaining low levels of debt at the holding company
level and the significant reduction in external debt at Terasen, the
Corporation's strong credit metrics, and the Corporation's demonstrated ability
and continued focus of acquiring and integrating stable regulated utility
businesses financed on a conservative basis.
Capital Program: The Corporation's principal businesses of regulated gas and
electricity distribution are capital intensive. Capital investment in
infrastructure is required to ensure continued and enhanced performance,
reliability and safety of the gas and electricity systems and to meet customer
growth. All costs considered to be maintenance and repairs are expensed as
incurred. Costs related to replacements, upgrades and betterments of capital
assets are capitalized as incurred.
During the first half of 2010, gross consolidated capital expenditures were $432
million. A breakdown of gross capital expenditures by segment for the first half
of 2010 is provided in the following table.
----------------------------------------------------------------------------
Gross Capital Expenditures (Unaudited) (1)
Year-to-date June 30, 2010 ($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Elec- Regu- Elec-
Tera- tric lated tric Non-
sen Fortis New- Utili- Utili- Utili- Regu-
Gas Alber- found- ties - ties - ties lated - Fortis
Compa- ta Fortis- land Cana- Cana- -Carib- Utili- Proper-
nies (2) BC Power dian dian bean ty (3) ties Total
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110 153 63 36 21 383 36 4 9 432
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(1) Relates to utility capital assets, income producing properties and
intangible assets and includes capital expenditures associated with
assets under construction. Includes asset removal and site restoration
expenditures, net of salvage proceeds, for those utilities where such
expenditures are permissible in rate base in 2010. Excludes capitalized
amortization and non-cash equity component of the allowance for funds
used during construction
(2) Includes payments made to AESO for investment in transmission capital
projects
(3) Includes non-regulated generation and corporate capital expenditures
There has been no material change in forecast gross consolidated capital
expenditures for 2010 from the approximate $1.1 billion forecast as was
disclosed in the MD&A for the year ended December 31, 2009. Planned capital
expenditures are based on detailed forecasts of energy demand, weather, cost of
labour and materials, as well as other factors, including economic conditions,
which could change and cause actual expenditures to differ from forecasts.
There are no significant updates in the overall expected level, nature and
timing of the Corporation's significant capital projects from those disclosed in
the MD&A for the year ended December 31, 2009, except as described below.
During 2010, FortisAlberta has continued with the replacement of conventional
customer meters with automated meter reading technology. The total project cost,
including the pilot program, is now expected to be approximately $141 million, a
decrease from $155 million forecast at December 31, 2009. The capital cost of
this project may be further updated, pending negotiation with customer groups
and regulatory approval.
In May 2010, Fortis Turks and Caicos received delivery of one of two
diesel-powered generating units with a combined generating capacity of
approximately 18 MW. The first unit is expected to be commissioned in September
2010.
Over the five-year period 2010 through 2014, consolidated gross capital
expenditures are expected to approach $5 billion. Approximately 71 per cent of
the capital spending is expected to be incurred at the Regulated Electric
Utilities, driven by FortisAlberta and FortisBC, and 27 per cent of the capital
spending is expected to be incurred at the Regulated Gas Utilities.
Approximately 2 per cent is expected to be incurred at the non-regulated
operations. Capital expenditures at the Regulated Utilities are subject to
regulatory approval.
Cash Flow Requirements: At the operating subsidiary level, it is expected that
operating expenses and interest costs will generally be paid out of subsidiary
operating cash flows, with varying levels of residual cash flow available for
subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings
under credit facilities may be required from time to time to support seasonal
working capital requirements. Cash required to complete subsidiary capital
expenditure programs is also expected to be financed from a combination of
borrowings under credit facilities, equity injections from Fortis and long-term
debt issues.
The Corporation's ability to service its debt obligations and pay dividends on
its common and preference shares is dependent on the financial results of the
operating subsidiaries and the related cash payments from these subsidiaries.
Certain regulated subsidiaries may be subject to restrictions which may limit
their ability to distribute cash to Fortis. Cash required of Fortis to support
subsidiary capital expenditure programs and finance acquisitions is expected to
be derived from a combination of borrowings under the Corporation's committed
credit facility and proceeds from the issuance of common shares, preference
shares and long-term debt. Depending on the timing of cash payments from the
subsidiaries, borrowings under the Corporation's committed credit facility may
be required from time to time to support the servicing of debt and payment of
dividends.
As at June 30, 2010, management expects consolidated long-term debt maturities
and repayments to average approximately $300 million annually over the next five
years. The combination of available credit facilities and relatively low annual
debt maturities and repayments provide the Corporation and its subsidiaries with
flexibility in the timing of access to capital markets.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009
Rate Application in June 2008, Belize Electricity does not meet certain debt
covenant financial ratios related to loans with the International Bank for
Reconstruction and Development and the Caribbean Development Bank totalling $6
million (BZ$11 million) as at June 30, 2010.
As the hydroelectric assets and water rights of the Exploits Partnership had
been provided as security for the Exploits Partnership term loan, the
expropriation of such assets and rights by the Government of Newfoundland and
Labrador constituted an event of default under the loan. The term loan is
without recourse to Fortis and was approximately $58 million as at June 30, 2010
(December 31, 2009 - $59 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan are
being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to the expropriation
matters.
Except for the debt at Belize Electricity and the Exploits Partnership, as
discussed above, Fortis and its subsidiaries were in compliance with debt
covenants as at June 30, 2010 and are expected to remain compliant throughout
2010.
Credit Facilities: As at June 30, 2010, the Corporation and its subsidiaries had
consolidated credit facilities of approximately $2.1 billion, of which $1.4
billion was unused, including $403 million unused under the Corporation's $600
million committed revolving credit facility. The credit facilities are
syndicated almost entirely with the seven largest Canadian banks, with no one
bank holding more than 25 per cent of these facilities. Approximately $2.0
billion of the total credit facilities are committed facilities, the majority of
which currently have maturities between 2011 and 2013.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities
(Unaudited) As at
-
Corporate Regulated Fortis June 30, December
($ millions) and Other Utilities Properties 2010 31, 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 645 1,455 13 2,113 2,153
Credit
facilities
utilized:
Short-term
borrowings - (218) (1) (219) (415)
Long-term
debt
(including
current
portion) (197) (225) - (422) (208)
Letters of
credit
outstanding (1) (111) - (112) (100)
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Credit
facilities
unused 447 901 12 1,360 1,430
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As at June 30, 2010 and December 31, 2009, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In February 2010, Maritime Electric renewed its $50 million unsecured committed
revolving credit facility, which matures annually in March. During the second
quarter of 2010, Maritime Electric increased its unsecured committed revolving
credit facility by $10 million.
In April 2010, FortisBC amended its credit facility agreement obtaining an
extension to the maturity of its $150 million unsecured committed revolving
credit facility with $100 million now maturing in May 2013 and $50 million now
maturing in May 2011.
In May 2010, TGVI entered into a two-year $300 million unsecured committed
revolving credit facility to replace its $350 million credit facility that was
due to mature in January 2011. The terms of the new $300 million credit facility
are substantially similar to the terms of the former $350 million credit
facility, except for an increase in pricing.
In May 2010, Newfoundland Power exercised an option to extend its $100 million
unsecured committed credit facility ("Amended Credit Facility") to August 2013
from August 2011. The Amended Credit Facility agreement is expected to reflect
an increase in pricing but, otherwise, contain substantially similar terms and
conditions as the current credit facility agreement. The amended agreement is
expected to be finalized in August 2010.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current
liabilities, other assets and other liabilities in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or nature of these instruments. The fair
value of long-term debt is calculated using quoted market prices when available.
When quoted market prices are not available, the fair value is determined by
discounting the future cash flows of the specific debt instrument at an
estimated yield to maturity equivalent to benchmark government bonds or treasury
bills, with similar terms to maturity, plus a market credit risk premium equal
to that of issuers of similar credit quality. Since the Corporation does not
intend to settle the long-term debt prior to maturity, the fair value estimate
does not represent an actual liability and, therefore, does not include exchange
or settlement costs. The fair value of the Corporation's preference shares is
determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt
and preference shares were as follows.
--------------------------------------------------------------------------
Financial Instruments
(Unaudited) As at
June 30, 2010 December 31, 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Long-term debt,
including current
portion (1) 5,523 6,160 5,502 5,906
Preference shares,
classified as debt
(2) 320 340 320 348
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Carrying value as at June 30, 2010 excludes unamortized deferred
financing costs of $38 million (December 31, 2009 - $39 million) and
capital lease obligations of $38 million (December 31, 2009 - $37
million).
(2) Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was $595
million as at June 30, 2010 (December 31, 2009 - carrying value $347
million; fair value $356 million).
--------------------------------------------------------------------------
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, Fortis Turks and Caicos, FortisUS
Energy Corporation and Belize Electric Company Limited is the US dollar. The
Belizean dollar is pegged to the US dollar at BZ$2.00=US$1.00.
As at June 30, 2010, all of the Corporation's corporately held US$390 million
(December 31, 2009 - US$390 million) long-term debt had been designated as a
hedge of a portion of the Corporation's foreign net investments. As at June 30,
2010, the Corporation had approximately US$187 million (December 31, 2009 -
US$174 million) in foreign net investments remaining to be hedged. Foreign
currency exchange rate fluctuations associated with the translation of the
Corporation's corporately held US dollar borrowings designated as hedges are
recorded in other comprehensive income and serve to help offset unrealized
foreign currency gains and losses on the foreign net investments, which are also
recorded in other comprehensive income.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes.
The following table summarizes the valuation of the Corporation's consolidated
derivative financial instruments.
Derivative Financial Instruments (Unaudited) As at
June 30, 2010 December 31, 2009
Estimated Estimated
Term to Carrying Fair Carrying Fair
Asset Maturity Number of Value ($ Value($ Value ($ Value($
(Liability) (years) Contracts millions) millions) millions) millions)
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Interest rate less than
swap 1 1 - - - -
Foreign
exchange
forward
contracts 1 to 2 2 1 1 - -
Natural gas
derivatives:
Swaps and
options Up to 4 193 (156) (156) (119) (119)
Gas purchase
contract
premiums Up to 3 47 (4) (4) (3) (3)
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The interest rate swap is held by Fortis Properties and is designated as a hedge
of the cash flow risk related to floating-rate long-term debt and matures in
October 2010. The effective portion of changes in the value of the interest rate
swap at Fortis Properties is recorded in other comprehensive income.
The foreign exchange forward contracts are held by the Terasen Gas companies.
During the first quarter of 2010, TGI entered into a foreign exchange forward
contract to hedge the cash flow risk related to approximately US$12 million
remaining to be paid under a contract for the implementation of a customer
information system. TGVI also hedges the cash flow risk related to approximately
US$4 million remaining to be paid under a contract for the construction of a
liquefied natural gas storage facility.
The natural gas derivatives are held by the Terasen Gas companies and are used
to fix the effective purchase price of natural gas, as the majority of the
natural gas supply contracts have floating, rather than fixed, prices. The price
risk-management strategy of the Terasen Gas companies aims to improve the
likelihood that natural gas prices remain competitive with electricity rates,
temper gas price volatility on customer rates and reduce the risk of regional
price discrepancies.
The changes in the fair values of the foreign exchange forward contracts and
natural gas derivatives are deferred as a regulatory asset or liability, subject
to regulatory approval, for recovery from, or refund to, customers in future
rates. The fair values of the foreign exchange forward contracts were recorded
in accounts receivable as at June 30, 2010 and as at December 31, 2009. The fair
values of the natural gas derivatives were recorded in accounts payable as at
June 30, 2010 and as at December 31, 2009.
The interest rate swap is valued at the present value of future cash flows based
on published forward future interest rate curves. The foreign exchange forward
contracts are valued using the present value of cash flows based on a market
foreign exchange rate and the foreign exchange forward rate curve. The natural
gas derivatives are valued using the present value of cash flows based on market
prices and forward curves for the commodity cost of natural gas. The fair values
of the foreign exchange forward contracts and natural gas derivatives are
estimates of the amounts the Terasen Gas companies would have to receive or pay
if forced to settle all outstanding contracts as at the balance sheet dates.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
As at June 30, 2010, the Corporation had no off-balance sheet arrangements, such
as transactions, agreements or contractual arrangements with unconsolidated
entities, structured finance entities, special purpose entities or variable
interest entities, that are reasonably likely to materially affect liquidity or
the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
A detailed discussion of the Corporation's significant business risks is
provided in the MD&A for the year ended December 31, 2009. There were no changes
in the Corporation's significant business risks during the first half of 2010
from those disclosed in the MD&A for the year ended December 31, 2009, except
for those described below.
Regulatory Risk: In July 2010, the AUC issued its decision on FortisAlberta's
2010 and 2011 revenue requirements application, the effects of which are
expected to be reflected in the third quarter of 2010. Maritime Electric also
received a regulatory decision on its revenue requirements application for rates
effective August 1, 2010 with an allowed ROE of 9.75 per cent approved for each
of 2010 and 2011. See the "Regulatory Highlights - Material Regulatory Decisions
and Applications" section of this MD&A.
Capital Resources and Liquidity Risk - Credit Ratings: Fortis and its regulated
utilities do not anticipate any material adverse rating actions by the credit
rating agencies in the near term.
Year-to-date 2010, Moody's has confirmed its existing debt credit ratings for
TGI, TGVI, FortisAlberta and Newfoundland Power. Moody's, however, upgraded
FortisBC's senior unsecured debt credit rating to Baa1 from Baa2. The credit
rating upgrade for FortisBC reflects progress made by the Company in addressing
issues previously identified as credit challenges. DBRS has confirmed its
existing debt credit ratings for TGI, and its existing credit rating of the
Corporation's unsecured debt at BBB(high) while changing the trend to 'Positive'
from 'Stable'. See the "Liquidity and Capital Resources - Credit Ratings"
section of this MD&A. S&P has also confirmed its existing debt credit ratings
for FortisAlberta and the Corporation, and its existing corporate credit rating
for Maritime Electric. S&P, however, lowered Maritime Electric's senior secured
debt credit rating to A- from A and revised the recovery rating on the debt to
'1' from '1+'. The revised recovery rating and lower senior secured debt credit
rating reflects Maritime Electric's ratio of collateral relative to the maximum
amount of first mortgage bonds allowed under the Company's indenture being less
than 1.5 times.
Defined Benefit Pension Plan Performance and Funding Requirements: As at June
30, 2010, the fair value of the Corporation's consolidated defined benefit
pension plan assets was $665 million, up $4 million, or 0.6 per cent, from $661
million as at December 31, 2009.
CHANGES IN ACCOUNTING POLICIES AND STANDARDS
Effective January 1, 2010, as required by the regulator, FortisAlberta began
capitalizing to utility capital assets a portion of the amortization of utility
capital assets, such as tools and vehicles, used in the construction of other
assets. During the three and six months ended June 30, 2010, amortization of $1
million and $2 million, respectively, was capitalized.
Effective January 1, 2010, as a result of the BCUC-approved NSAs related to 2010
and 2011 revenue requirements, the Terasen Gas companies adopted the following
new accounting policies:
i. Asset removal costs are now recorded in operating expenses on the
consolidated statement of earnings. The annual amount of such costs
approved for recovery in customer rates in 2010 is approximately $8
million. Actual costs incurred in excess of or below the approved amount
are to be recorded in a regulatory deferral account for recovery from,
or refund to, customers in future rates, beginning in 2012. Removal
costs are direct costs incurred by the Terasen Gas companies in taking
assets out of service, whether through actual removal of the assets or
through the disconnection of the assets from the transmission or
distribution system. For the three months ended June 30, 2010, actual
asset removal costs of approximately $3 million were incurred, with $2
million recorded in operating expenses and $1 million deferred as a
regulatory asset. For the six months ended June 30, 2010, actual asset
removal costs of approximately $5 million were incurred, with
approximately $4 million recorded in operating expenses and $1 million
deferred as a regulatory asset. Prior to January 1, 2010, asset removal
costs were recorded against accumulated amortization on the consolidated
balance sheet.
ii. CIACs are now amortized to revenue. During the three and six months
ended June 30, 2010, CIACs of approximately $2 million and $5 million,
respectively, were amortized to revenue on the consolidated statement of
earnings. Prior to January 1, 2010, amortization of CIACs was recorded
against amortization expense on the consolidated statement of earnings.
iii.Gains and losses on the sale or disposal of utility capital assets are
now recorded in a regulatory deferral account on the consolidated
balance sheet for recovery from, or refund to, customers in future
rates, subject to regulatory approval. During the three and six months
ended June 30, 2010, losses of approximately $2 million and $5 million,
respectively, were deferred and recorded as a regulatory asset on the
consolidated balance sheet. Prior to January 1, 2010, gains and losses
on the sale or disposal of utility capital assets were recorded against
accumulated amortization on the consolidated balance sheet.
iv. Amortization of utility capital assets and intangible assets now
commences the month after the assets are available for use. Prior to
January 1, 2010, amortization commenced the year following when the
assets became available for use. During 2010, additional amortization
expense of approximately $2 million is expected to be incurred, due to
the change in commencement of amortization of utility capital assets and
intangible assets.
Business Combinations
Effective January 1, 2010, the Corporation early adopted the new Canadian
Institute of Chartered Accountants ("CICA") Handbook Section 1582, Business
Combinations, together with Section 1601, Consolidated Financial Statements and
Section 1602, Non-Controlling Interests. As a result of adopting Section 1582,
changes in the determination of the fair value of the assets and liabilities of
an acquiree in a business combination results in a different calculation of
goodwill with respect to acquisitions on or after January 1, 2010. Such changes
include the expensing of acquisition-related costs incurred during a business
acquisition, rather than recording them as a capital transaction, and the
disallowance of recording restructuring accruals by the acquirer. The adoption
of Section 1582 did not have a material impact on the Corporation's interim
unaudited consolidated financial statements in the first half of 2010.
Section 1601 establishes standards for the preparation of consolidated financial
statements. Section 1602 establishes standards for accounting for
non-controlling interests in a subsidiary in consolidated financial statements
subsequent to a business combination. The adoption of Sections 1601 and 1602
resulted in non-controlling interests being presented as components of equity,
rather than as liabilities, on the consolidated balance sheet. Also, net
earnings and components of other comprehensive income attributable to the owners
of the parent company and to non-controlling interests are now separately
disclosed on the consolidated statement of earnings and consolidated statement
of comprehensive income.
FUTURE ACCOUNTING CHANGES
Transition to International Financial Reporting Standards
A detailed discussion of the Corporation's transition to International Financial
Reporting Standards ("IFRS") is provided in the MD&A for the year ended December
31, 2009. The Corporation is still unable to fully determine the impact on its
future financial position and results of operations of the transition to IFRS,
particularly as it relates to the accounting for rate-regulated activities.
Completion of the Rate-Regulated Activities Project by the International
Accounting Standards Board ("IASB") has been delayed based on comments received
in response to the IASB's July 2009 Exposure Draft on Rate-Regulated Activities
and a decision by the IASB to conduct further research.
The IASB met in July 2010 and discussed the key issue of whether regulatory
assets and liabilities can be recognized based on the current IFRS - Framework
for the Preparation and Presentation of Financial Statements. As a result of
those meetings, the IASB decided to continue with the project; however, no
decision was made as to whether regulatory assets and liabilities can be
recognized under IFRS. A final standard, if any, is still not anticipated before
the latter half of 2011.
On July 23, 2010, the Canadian Accounting Standards Board ("AcSB") met to
discuss the IASB's latest decisions with respect to the Rate-Regulated
Activities Project. On July 28, 2010, the AcSB issued an Exposure Draft
proposing that qualifying entities with rate-regulated activities be permitted,
but not required, to continue applying the accounting standards in Part V of the
CICA Handbook for an additional two years. A qualifying entity would be an
entity that: (i) has activities subject to rate regulation meeting the
definition of that term in Generally Accepted Accounting Principles, paragraph
1100.32B, in Part V of the CICA Handbook; and (ii) in accordance with Accounting
Guideline AcG-19, Disclosures by Entities Subject to Rate Regulation, discloses
that it has accounted for a transaction or event differently than it would have
in the absence of rate regulation (i.e., that it has recognized regulatory
assets and liabilities). The Exposure Draft also proposes that an entity
choosing to defer its IFRS changeover date disclose that fact and when it will
first present financial statements in accordance with IFRS.
The Exposure Draft provides a two-year deferral of the adoption of IFRS for
qualifying entities, based on the expectation that the IASB will complete its
project on Rate-Regulated Activities in 2011 or 2012, and gives qualifying
entities sufficient time to meet the requirements of a new IFRS on
rate-regulated activities in the event one is issued late in, or shortly
following, what would otherwise be their year of IFRS adoption.
The Corporation is reviewing the AcSB's Exposure Draft and will provide
comments, as requested, by August 31, 2010. The AcSB has indicated its intention
to redeliberate the proposal based on comments received and expects to issue the
proposed amendment by no later than December 2010.
While the Corporation's IFRS Conversion Project has proceeded as planned in
preparation for the adoption of IFRS on January 1, 2011, Fortis and its
rate-regulated subsidiaries do qualify for the proposed deferral option. If the
Exposure Draft is approved, the Corporation will elect to defer the adoption of
IFRS until 2013 and will, therefore, continue to prepare its consolidated
financial statements in accordance with Part V of the CICA Handbook for all
interim and annual periods ending on or before December 31, 2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial
statements in accordance with Canadian GAAP requires management to make
estimates and judgments that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the consolidated financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are based on
historical experience, current conditions and various other assumptions believed
to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory
environments in which the Corporation's utilities operate often require amounts
to be recorded at estimated values until these amounts are finalized pursuant to
regulatory decisions or other regulatory proceedings. Due to changes in facts
and circumstances and the inherent uncertainty involved in making estimates,
actual results may differ significantly from current estimates. Estimates and
judgments are reviewed periodically and, as adjustments become necessary, are
reported in earnings in the period they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the first half of 2010 from
those disclosed in the Corporation's MD&A for the year ended December 31, 2009,
except for those described below.
Capital Asset Amortization: As a result of a recent depreciation study and
BCUC-approved NSAs related to TGI and TGVI's 2010 and 2011 revenue requirements,
annual amortization expense at the Terasen Gas companies is expected to increase
in 2010, reflecting an increase in the composite depreciation rate to 2.79 per
cent for 2010 from 2.63 per cent for 2009. The increase in amortization has been
approved for recovery in current customer delivery rates.
Asset-Retirement Obligations: During the second quarter of 2010, FortisBC
obtained sufficient information to determine an estimate of the fair value and
timing of the estimated future expenditures associated with the removal of
polychlorinated biphenyls ("PCB")-contaminated oil from its electrical
equipment. All factors used in estimating the Company's asset-retirement
obligation represent management's best estimate of the fair value of the costs
required to meet existing legislation or regulations. It is reasonably possible
that volumes of contaminated assets, inflation assumptions, cost estimates to
perform the work and the assumed pattern of annual cash flows may differ
significantly from the Company's current assumptions. In addition, in order to
remove certain PCB-contaminated oil, the ability to take maintenance outages in
critical facilities may impact the timing of expenditures. The asset-retirement
obligation may change from period to period because of the changes in the
estimation of these uncertainties. As at June 30, 2010, FortisBC has recognized
approximately $3 million in asset-retirement obligations, which have been
classified on the consolidated balance sheet as long-term other liabilities with
the offset to utility capital assets.
Capitalized Overhead: As required by their regulator, the Terasen Gas companies
capitalize overhead costs not directly attributable to specific capital projects
but related to the overall capital program. Effective January 1, 2010, as
provided in the BCUC-approved NSAs as described above, the percentage for
calculating and capitalizing general overhead costs to utility capital assets at
the Terasen gas companies has changed. The percentage of total general operating
and maintenance costs being allocated and capitalized to utility capital assets
has decreased from 16 per cent to 14 per cent. As a result of this change,
operating expenses increased approximately $1 million for the second quarter and
approximately $2 million year to date over the same periods in 2009, with
corresponding decreases in utility capital assets. The resulting increase in
operating expenses has been approved for recovery in current customer delivery
rates.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with ordinary course business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations. There were no material changes in the
Corporation's contingencies from those disclosed in the MD&A for the year ended
December 31, 2009, except for those described below.
Terasen
TGI has been disputing a $7 million assessment of British Columbia Social
Services Tax representing additional Provincial Sales Tax and interest on the
Southern Crossing Pipeline, which was completed in 2000. The amount was paid in
full in 2006 to avoid the accrual of further interest and is recorded as a
long-term regulatory deferral asset. TGI was successful in its appeal to the
Supreme Court of British Columbia in June 2009. The Province of British Columbia
was granted leave to appeal the decision to the British Columbia Court of Appeal
in October 2009. The hearing took place in May 2010 and the British Columbia
Court of Appeal was unanimous in dismissing the Province of British Columbia's
appeal.
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 the rupture in July 2007
of an oil pipeline owned and operated by Kinder Morgan. Terasen has filed a
statement of defence but the claim is in its early stages. During the second
quarter of 2010, Terasen was added as a third party in all of the related
actions and all claims are expected to be tried at the same time. The amount and
outcome of the actions are indeterminable at this time and, accordingly, no
amount has been accrued in the consolidated financial statements.
Maritime Electric
In June 2010, Maritime Electric reached a Settlement Agreement with Canada
Revenue Agency related to the reassessment of the Company's 1997-2004 taxation
years. In the Settlement Agreement, Maritime Electric's treatment of the Energy
Cost Adjustment Mechanism was accepted; however, the reassessments with respect
to customer rebate adjustments and the Company's settlement payment to New
Brunswick Power regarding the write-down of Point Lepreau would stand. The
Company has provided for the entire amount of the reassessment and expects final
reassessments with respect to all affected taxation years by the end of 2010.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended September 30, 2008 through June 30, 2010. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements which, in the opinion of management, have been
prepared in accordance with Canadian GAAP and as required by utility regulators.
The timing of the recognition of certain assets, liabilities, revenue and
expenses, as a result of regulation, may differ from that otherwise expected
using Canadian GAAP for non-regulated entities. The differences and nature of
regulation are disclosed in Notes 2 and 4 to the Corporation's 2009 annual
audited consolidated financial statements. The quarterly financial results are
not necessarily indicative of results for any future period and should not be
relied upon to predict future performance.
--------------------------------------------------------------------------
Summary of Quarterly Results (Unaudited)
Net Earnings
Attributable
to Common
Equity
Revenue ($ Shareholders
Quarter Ended millions) ($ millions) Earnings per Common Share
------------------------------
Basic($) Diluted ($)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
June 30, 2010 836 55 0.32 0.32
March 31, 2010 1,076 100 0.58 0.56
December 31, 2009 1,020 81 0.48 0.46
September 30, 2009 665 36 0.21 0.21
June 30, 2009 756 53 0.31 0.31
March 31, 2009 1,202 92 0.54 0.52
December 31, 2008 1,181 76 0.48 0.46
September 30, 2008 727 49 0.31 0.31
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A summary of the past eight quarters reflects the Corporation's continued
organic growth and growth from acquisitions, as well as the seasonality
associated with its businesses. Interim results will fluctuate due to the
seasonal nature of gas and electricity demand and water flows, as well as the
timing and recognition of regulatory decisions. Revenue is also affected by the
cost of fuel and purchased power and the commodity and mid-stream cost of
natural gas, which are flowed through to customers without markup. Given the
diversified nature of the Fortis subsidiaries, seasonality may vary. Because of
natural gas consumption patterns, the earnings of the Terasen Gas companies are
highest in the first and fourth quarters. Financial results from May 1, 2009
have been impacted, as expected, by the loss of revenue and earnings subsequent
to the expiration, in April 2009, of the water rights of the Rankine
hydroelectric generating facility in Ontario. Financial results for the fourth
quarter ended December 31, 2009 reflected the favourable cumulative retroactive
impact associated with an increase in the allowed ROEs for 2009 for
FortisAlberta and TGI, and an increase in the equity component at FortisAlberta.
Financial results for the fourth quarter ended December 31, 2008 included two
additional months of contribution from Caribbean Utilities, resulting from a
change in the utility's fiscal year end. To a lesser degree, financial results
from November 2008 were impacted by the acquisition of the Sheraton Hotel
Newfoundland, from April 2009 by the acquisition of the Holiday Inn Select
Windsor and from October 2009 by the acquisition of Algoma Power.
June 2010/June 2009 - Net earnings attributable to common equity shareholders
were $55 million, or $0.32 per common share, for the second quarter of 2010
compared to earnings of $53 million, or $0.31 per common share, for the second
quarter of 2009. The increase in earnings was driven by the Terasen Gas
companies and FortisBC, partially offset by higher corporate expenses. The
increase in earnings at the Terasen Gas companies related to higher allowed ROEs
and equity component. The improvement in earnings at FortisBC was the result of
a higher allowed ROE and growth in electrical infrastructure investment,
partially offset by lower electricity sales due to cooler weather experienced in
June 2010. The increase in corporate expenses was mainly due to higher business
development costs and preference share dividends, partially offset by higher
interest income related to increased inter-company lending. Earnings at
FortisAlberta were comparable quarter over quarter. The impact of a higher
allowed ROE and equity component, compared to those reflected in FortisAlberta's
earnings for the second quarter of 2009, combined with growth in electrical
infrastructure investment and customers was mainly offset by lower corporate
income tax recoveries and lower net transmission revenue.
March 2010/March 2009 - Net earnings attributable to common equity shareholders
were $100 million, or $0.58 per common share, for the first quarter of 2010
compared to earnings of $92 million, or $0.54 per common share, for the first
quarter of 2009. The increase in earnings was led by the Terasen Gas companies
associated with an increase in the allowed ROEs and equity component. Results
also reflected: (i) improved performance at FortisAlberta, associated with an
increase in the allowed ROE and equity component combined with growth in
electrical infrastructure investment and customers; and (ii) increased earnings
at Newfoundland Power, mainly due to growth in electrical infrastructure
investment, increased electricity sales and timing differences favourably
impacting operating expenses during the quarter. Earnings' growth was tempered
by: (i) lower earnings' contribution from non-regulated hydroelectric generation
operations due to loss of earnings subsequent to the expiration of the Rankine
water rights in April 2009; (ii) lower contribution from Caribbean Regulated
Electric Utilities associated with the unfavourable impact of foreign exchange
translation, and earnings in the first quarter of 2009 including an approximate
$1 million one-time gain; and (iii) higher preference share dividends.
December 2009/December 2008 - Net earnings attributable to common equity
shareholders were $81 million, or $0.48 per common share, for the fourth quarter
of 2009 compared to earnings of $76 million, or $0.48 per common share, for the
fourth quarter of 2008. Fourth quarter results for 2009 were favourably impacted
by a one-time $3 million adjustment to future income taxes related to prior
periods at FortisOntario and were unfavourably impacted by a one-time $5 million
after-tax provision for additional costs related to the conversion of Whistler
customer appliances from propane to natural gas. Fourth quarter results for 2008
included two additional months of earnings' contribution from Caribbean
Utilities (August and September 2008) of approximately $2 million due to a
change in the utility's fiscal year end. Excluding the above one-time items,
earnings increased $9 million quarter over quarter. The increase was driven by:
(i) the approximate $10 million cumulative retroactive impact in the fourth
quarter of 2009 associated with the increase in the allowed ROEs for 2009 for
FortisAlberta and TGI, and an increase in the equity component at FortisAlberta;
and (ii) a change in depreciation estimates at Fortis Turks and Caicos, which
favourably impacted amortization expense for the fourth quarter of 2009. The
increase was partially offset by lower earnings' contribution from non-regulated
hydroelectric generation operations due to loss of earnings subsequent to the
expiration of the Rankine water rights in April 2009.
September 2009/September 2008 - Net earnings attributable to common equity
shareholders were $36 million, or $0.21 per common share, for the third quarter
of 2009 compared to earnings of $49 million, or $0.31 per common share, for the
third quarter of 2008. Third quarter 2008 results included a tax reduction of
approximately $7.5 million associated with the settlement of historical
corporate tax matters at Terasen and a $4.5 million recovery of future income
taxes, which was previously expensed during the first half of 2008 at
FortisAlberta. Earnings were $1 million lower quarter over quarter, excluding
the above one-time tax reductions. The impact of lower effective corporate
income taxes at the Terasen Gas companies and growth in electrical
infrastructure investment and higher net transmission revenue at FortisAlberta
was more than offset by lower earnings from non-regulated hydroelectric
generation and lower earnings at Newfoundland Power. The decrease in earnings
from non-regulated hydroelectric generation operations was primarily associated
with the loss of earnings subsequent to the expiration of the Rankine water
rights in April 2009. Lower earnings at Newfoundland Power were largely
associated with higher operating expenses and amortization costs.
OUTLOOK
The Corporation's significant capital program, which is expected to be
approximately $1.1 billion in 2010 and approach $5 billion over the five-year
period from 2010 through 2014, should drive growth in earnings and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing
on strategic opportunities to acquire regulated electric and natural gas
utilities in the United States, Canada and the Caribbean. Fortis will also
pursue growth in its non-regulated businesses in support of its regulated
utility growth strategy.
OUTSTANDING SHARE DATA
As at August 3, 2010, the Corporation had issued and outstanding 172.9 million
common shares; 5.0 million First Preference Shares, Series C; 8.0 million First
Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2
million First Preference Shares, Series G; and 10.0 million First Preference
Shares, Series H. Only the common shares of the Corporation have voting rights.
The number of common shares of Fortis that would be issued if all outstanding
stock options, convertible debt and First Preference Shares, Series C and E were
converted as at August 3, 2010 is as follows:
---------------------------------------------------------------------------
Potential Conversion of Securities into Common Shares Number of Common
(Unaudited) As at August 3, 2010Security Shares(millions)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Stock Options 5.2
Convertible Debt 1.4
First Preference Shares, Series C 4.4
First Preference Shares, Series E 7.2
---------------------------------------------------------------------------
Total 18.2
---------------------------------------------------------------------------
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Additional information, including the Fortis 2009 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and six months ended June 30, 2010 and 2009
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
June 30, December 31,
2010 2009
--------------------------------------------------------------------------
(Notes 2 & 21)
ASSETS
Current assets
Cash and cash equivalents $ 71 $ 85
Accounts receivable 517 595
Prepaid expenses 15 16
Regulatory assets (Note 5) 256 223
Inventories (Note 6) 144 178
Future income taxes 17 29
----------------------------------
1,020 1,126
Other assets 170 174
Regulatory assets (Note 5) 783 747
Future income taxes 23 17
Utility capital assets 7,939 7,697
Income producing properties 560 559
Intangible assets 272 282
Goodwill 1,562 1,560
----------------------------------
$ 12,329 $ 12,162
--------------------------------------------------------------------------
--------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 19) $ 219 $ 415
Accounts payable and accrued charges 805 852
Dividends payable 52 3
Income taxes payable 20 23
Regulatory liabilities (Note 5) 46 53
Current installments of long-term debt
and capital lease obligations (Note 7) 158 224
Future income taxes 8 24
----------------------------------
1,308 1,594
Other liabilities 306 295
Regulatory liabilities (Note 5) 474 444
Future income taxes 591 570
Long-term debt and capital lease
obligations (Note 7) 5,365 5,276
Preference shares 320 320
----------------------------------
8,364 8,499
----------------------------------
Shareholders' equity
Common shares (Note 8) 2,537 2,497
Preference shares (Note 9) 592 347
Contributed surplus 12 11
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss
(Note 11) (79) (83)
Retained earnings 773 763
----------------------------------
3,840 3,540
Non-controlling interests 125 123
----------------------------------
3,965 3,663
----------------------------------
$ 12,329 $ 12,162
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Contingent liabilities and commitments (Note 20)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
2010 2009 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Note 2) (Note 2)
Revenue $ 836 $ 756 $ 1,912 $ 1,958
-----------------------------------------------
Expenses
Energy supply costs 367 319 919 1,026
Operating 202 189 404 382
Amortization 98 92 195 183
-----------------------------------------------
667 600 1,518 1,591
-----------------------------------------------
Operating income 169 156 394 367
Finance charges (Note 13) 88 88 178 176
-----------------------------------------------
Earnings before corporate
taxes 81 68 216 191
Corporate taxes (Note 14) 15 7 43 32
-----------------------------------------------
Net earnings $ 66 $ 61 $ 173 $ 159
-----------------------------------------------
-----------------------------------------------
Net earnings attributable
to:
Non-controlling
interests $ 3 $ 3 $ 4 $ 5
Preference equity
shareholders 8 5 14 9
Common equity
shareholders 55 53 155 145
-----------------------------------------------
$ 66 $ 61 $ 173 $ 159
-----------------------------------------------
-----------------------------------------------
Earnings per common share
(Note 8)
Basic $ 0.32 $ 0.31 $ 0.90 $ 0.85
Diluted $ 0.32 $ 0.31 $ 0.88 $ 0.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial
Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2010 2009 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Note 2) (Note 2)
Balance at beginning of
period $ 767 $ 682 $ 763 $ 634
Net earnings attributable
to common and preference
equity shareholders 63 58 169 154
-----------------------------------------------
830 740 932 788
Dividends on common shares (49) (44) (145) (88)
Dividends on preference
shares classified as
equity (8) (5) (14) (9)
-----------------------------------------------
Balance at end of period $ 773 $ 691 $ 773 $ 691
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial
Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(Note 2) (Note 2)
Net earnings $ 66 $ 61 $ 173 $ 159
---------------------------------------
---------------------------------------
Other comprehensive income (loss)
Unrealized foreign currency
translation gains (losses) on net
investments in self-sustaining
foreign operations 28 (52) 8 (28)
(Losses) gains on hedges of net
investments in self-sustaining
foreign operations (19) 40 (5) 22
Corporate tax recovery (expense) 3 (6) 1 (3)
---------------------------------------
Unrealized foreign currency
translation gains (losses), net of
hedging activities and tax (Note
11) 12 (18) 4 (9)
---------------------------------------
Gain on derivative instruments
designated as cash flow hedges,
net of tax (Note 11) - 1 - 1
---------------------------------------
Comprehensive income $ 78 $ 44 $ 177 $ 151
---------------------------------------
---------------------------------------
Comprehensive income attributable
to:
Non-controlling interests $ 3 $ 3 $ 4 $ 5
Preference equity shareholders 8 5 14 9
Common equity shareholders 67 36 159 137
---------------------------------------
$ 78 $ 44 $ 177 $ 151
---------------------------------------
---------------------------------------
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2010 2009 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Note 2) (Note 2)
Operating activities
Net earnings $ 66 $ 61 $ 173 $ 159
Items not affecting cash:
Amortization - utility capital
assets and income producing
properties 88 81 174 160
Amortization - intangible
assets 9 9 20 20
Amortization - other 1 2 1 3
Future income taxes 2 4 (1) 7
Other (2) (4) (3) (7)
Change in long-term regulatory
assets and liabilities (4) 14 - 23
---------------------------------------
160 167 364 365
Change in non-cash operating
working capital 44 108 89 139
---------------------------------------
204 275 453 504
---------------------------------------
Investing activities
Change in other assets and other
liabilities 1 2 3 (5)
Capital expenditures - utility
capital assets (234) (264) (413) (474)
Capital expenditures - income
producing properties (3) (6) (9) (11)
Capital expenditures -
intangible assets (7) (7) (10) (11)
Contributions in aid of
construction 14 10 24 26
Business acquisition - (7) - (7)
---------------------------------------
(229) (272) (405) (482)
---------------------------------------
Financing activities
Change in short-term borrowings 55 (89) (126) (239)
Proceeds from long-term debt,
net of issue costs - 203 - 401
Repayments of long-term debt and
capital lease obligations (196) (85) (212) (91)
Net borrowings under committed
credit facilities 186 52 157 57
Advances from non-controlling
interests 1 - 1 -
Issue of common shares, net of
costs 16 11 39 24
Issue of preference shares, net
of costs - - 242 -
Dividends
Common shares (49) (44) (145) (88)
Preference shares (8) (5) (14) (9)
Subsidiary dividends paid to
non-controlling interests (2) (2) (4) (5)
---------------------------------------
3 41 (62) 50
---------------------------------------
Effect of exchange rate changes on
cash and cash equivalents 1 (1) - (1)
---------------------------------------
Change in cash and cash
equivalents (21) 43 (14) 71
Cash and cash equivalents,
beginning of period 92 94 85 66
-------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ 71 $ 137 $ 71 $ 137
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
16)
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 2010 and 2009 (unless otherwise
stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international
distribution utility holding company. Fortis segments its utility operations by
franchise area and, depending on regulatory requirements, by the nature of the
assets. Fortis also holds investments in non-regulated generation assets, and
commercial office and retail space and hotels, which are treated as two separate
segments. The Corporation's reporting segments allow senior management to
evaluate the operational performance and assess the overall contribution of each
segment to the 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 outlines each of the Corporation's reportable segments and is
consistent with the basis of segmentation as disclosed in the Corporation's 2009
annual audited consolidated financial statements.
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities in Canada
and the Caribbean are as follows:
a. Regulated Gas Utilities - Canadian: Consists of the Terasen Gas
companies, including Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver
Island) Inc. ("TGVI") and Terasen Gas (Whistler) Inc.
b. Regulated Electric Utilities - Canadian: Consists of FortisAlberta;
FortisBC; Newfoundland Power; and Other Canadian Electric Utilities,
which includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and
Power Company, Limited and, as of October 2009, Algoma Power Inc.
("Algoma Power").
c. Regulated Electric Utilities - Caribbean: Consists of Belize
Electricity, in which Fortis holds an approximate 70 per cent
controlling ownership interest; Caribbean Utilities, in which Fortis
holds an approximate 59 per cent controlling ownership interest; and
wholly owned Fortis Turks and Caicos, which includes P.P.C. Limited and
Atlantic Equipment & Power (Turks and Caicos) Ltd.
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generating
assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 21 hotels, comprised of more than 4,100
rooms, in eight Canadian provinces and approximately 2.8 million square feet of
commercial office and retail space primarily in Atlantic Canada.
CORPORATE AND OTHER
The Corporate and Other segment 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 and of Terasen's non-regulated wholly owned
subsidiary Terasen Energy Services Inc.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements do not include all of the
information and disclosures required in the annual consolidated financial
statements, and should be read in conjunction with the Corporation's 2009 annual
audited consolidated financial statements. Interim results will fluctuate due to
the seasonal nature of gas and electricity demand and water flows, as well as
the timing and recognition of regulatory decisions. Because of natural gas
consumption patterns, earnings of the Terasen Gas companies are highest in the
first and fourth quarters. Given the diversified group of companies, seasonality
may vary.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP") for
interim financial statements, following the same accounting policies and methods
as those used in preparing the Corporation's 2009 annual audited consolidated
financial statements, except as described below.
Effective January 1, 2010, as required by the regulator, FortisAlberta began
capitalizing to utility capital assets a portion of the amortization of utility
capital assets, such as tools and vehicles, used in the construction of other
assets. During the three and six months ended June 30, 2010, amortization of $1
million and $2 million, respectively, was capitalized.
Effective January 1, 2010, as a result of the British Columbia Utilities
Commission ("BCUC")-approved Negotiated Settlement Agreements ("NSAs") related
to 2010 and 2011 revenue requirements, the Terasen Gas companies adopted the
following new accounting policies:
i. Asset removal costs are now recorded in operating expenses on the
consolidated statement of earnings. The annual amount of such costs
approved for recovery in customer rates in 2010 is approximately $8
million. Actual costs incurred in excess of or below the approved amount
are to be recorded in a regulatory deferral account for recovery from,
or refund to, customers in future rates, beginning in 2012. Removal
costs are direct costs incurred by the Terasen Gas companies in taking
assets out of service, whether through actual removal of the assets or
through the disconnection of the assets from the transmission or
distribution system. For the three months ended June 30, 2010, actual
asset removal costs of approximately $3 million were incurred, with $2
million recorded in operating expenses and $1 million deferred as a
regulatory asset. For the six months ended June 30, 2010, actual asset
removal costs of approximately $5 million were incurred, with
approximately $4 million recorded in operating expenses and $1 million
deferred as a regulatory asset. Prior to January 1, 2010, asset removal
costs were recorded against accumulated amortization on the consolidated
balance sheet.
ii. Contributions in aid of construction ("CIACs") are now amortized to
revenue. During the three and six months ended June 30, 2010, CIACs of
approximately $2 million and $5 million, respectively, were amortized to
revenue on the consolidated statement of earnings. Prior to January 1,
2010, amortization of CIACs was recorded against amortization expense on
the consolidated statement of earnings.
iii.Gains and losses on the sale or disposal of utility capital assets are
now recorded in a regulatory deferral account on the consolidated
balance sheet for recovery from, or refund to, customers in future
rates, subject to regulatory approval. During the three and six months
ended June 30, 2010, losses of approximately $2 million and $5 million,
respectively, were deferred and recorded as a regulatory asset on the
consolidated balance sheet. Prior to January 1, 2010, gains and losses
on the sale or disposal of utility capital assets were recorded against
accumulated amortization on the consolidated balance sheet.
iv. Amortization of utility capital assets and intangible assets now
commences the month after the assets are available for use. Prior to
January 1, 2010, amortization commenced the year following when the
assets became available for use. During 2010, additional amortization
expense of approximately $2 million is expected to be incurred, due to
the change in commencement of amortization of utility capital assets and
intangible assets.
Effective January 1, 2010, the Corporation adopted the following new accounting
standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Business Combinations
Effective January 1, 2010, the Corporation early adopted the new CICA Handbook
Section 1582, Business Combinations, together with Section 1601, Consolidated
Financial Statements and Section 1602, Non-Controlling Interests. As a result of
adopting Section 1582, changes in the determination of the fair value of the
assets and liabilities of an acquiree in a business combination results in a
different calculation of goodwill with respect to acquisitions on or after
January 1, 2010. Such changes include the expensing of acquisition-related costs
incurred during a business acquisition, rather than recording them as a capital
transaction, and the disallowance of recording restructuring accruals by the
acquirer. The adoption of Section 1582 did not have a material impact on the
Corporation's interim consolidated financial statements for the three and six
months ended June 30, 2010.
Section 1601 establishes standards for the preparation of consolidated financial
statements. Section 1602 establishes standards for accounting for
non-controlling interests in a subsidiary in consolidated financial statements
subsequent to a business combination. The adoption of Sections 1601 and 1602
resulted in non-controlling interests being presented as components of equity,
rather than as liabilities, on the consolidated balance sheet. Also, net
earnings and components of other comprehensive income attributable to the owners
of the parent company and to non-controlling interests are now separately
disclosed on the consolidated statement of earnings and consolidated statement
of comprehensive income.
3. FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards
In October 2009, the Canadian Accounting Standards Board ("AcSB") re-confirmed
that publicly accountable enterprises in Canada will be required to apply
International Financial Reporting Standards ("IFRS"), in full and without
modification, beginning January 1, 2011. An IFRS transition date of January 1,
2011 would require the restatement, for comparative purposes, of amounts
reported on the Corporation's consolidated opening IFRS balance sheet as at
January 1, 2010 and amounts reported by the Corporation for the year ended
December 31, 2010.
Fortis is continuing to assess the financial reporting impacts of adopting IFRS.
In July 2009, the International Accounting Standards Board ("IASB") issued the
Exposure Draft - Rate-Regulated Activities. Based on the Exposure Draft,
regulatory assets and liabilities arising from activities subject to cost of
service regulation would be recognized under IFRS when certain conditions are
met. The ability to record regulatory assets and liabilities, as proposed in the
Exposure Draft, should reduce the earnings' volatility at the Corporation's
regulated utilities that may otherwise result under IFRS in the absence of an
accounting standard for rate-regulated activities, but will result in the
requirement to provide enhanced balance sheet presentation and note disclosures.
Completion of the IASB's Rate-Regulated Activities Project has been delayed
based on comments received in response to the Exposure Draft and a decision by
the IASB to conduct further research.
The IASB met in July 2010 and discussed the key issue of whether regulatory
assets and liabilities can be recognized based on the current IFRS - Framework
for the Preparation and Presentation of Financial Statements. As a result of
those meetings, the IASB decided to continue with the project; however, no
decision was made as to whether regulatory assets and liabilities can be
recognized under IFRS. A final standard, if any, is still not anticipated before
the latter half of 2011.
On July 23, 2010, the AcSB met to discuss the IASB's latest decisions with
respect to the Rate-Regulated Activities Project. On July 28, 2010, the AcSB
issued an Exposure Draft proposing that qualifying entities with rate-regulated
activities be permitted, but not required, to continue applying the accounting
standards in Part V of the CICA Handbook for an additional two years.
A qualifying entity would be an entity that: (i) has activities subject to rate
regulation meeting the definition of that term in Generally Accepted Accounting
Principles, paragraph 1100.32B, in Part V of the Handbook; and (ii) in
accordance with Accounting Guideline AcG-19, Disclosures by Entities Subject to
Rate Regulation, discloses that it has accounted for a transaction or event
differently than it would have in the absence of rate regulation (i.e., that it
has recognized regulatory assets and liabilities). The Exposure Draft also
proposes that an entity choosing to defer its IFRS changeover date disclose that
fact and when it will first present financial statements in accordance with
IFRS.
The Exposure Draft provides a two-year deferral of the adoption of IFRS for
qualifying entities based on the expectation that the IASB will complete its
project on rate-regulated activities in 2011 or 2012, and gives qualifying
entities sufficient time to meet the requirements of a new IFRS on
rate-regulated activities in the event one is issued late in, or shortly
following, what would otherwise be their year of IFRS adoption.
The Corporation is reviewing the AcSB's Exposure Draft and will provide
comments, as requested, by August 31, 2010. The AcSB has indicated its intention
to redeliberate the proposal based on comments received and expects to issue the
proposed amendment by no later than December 2010.
While the Corporation's IFRS Conversion Project has proceeded as planned in
preparation for the adoption of IFRS on January 1, 2011, Fortis and its
rate-regulated subsidiaries do qualify for the proposed deferral option. If the
Exposure Draft is approved, the Corporation will elect to defer the adoption of
IFRS until 2013 and will, therefore, continue to prepare its consolidated
financial statements in accordance with Part V of the CICA Handbook for all
interim and annual periods ending on or before December 31, 2012.
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 during the six months ended June 30,
2010, except for that described below and in Note 20 as it relates to
contingencies.
Capital Asset Amortization: As a result of a recent depreciation study and
BCUC-approved NSAs related to TGI and TGVI's 2010 and 2011 revenue requirements,
annual amortization expense at the Terasen Gas companies is expected to increase
in 2010, reflecting an increase in the composite depreciation rate to 2.79 per
cent for 2010 from 2.63 per cent for 2009. The increase in amortization has been
approved for recovery in current customer delivery rates.
Asset-Retirement Obligations: During the second quarter of 2010, FortisBC
obtained sufficient information to determine an estimate of the fair value and
timing of the estimated future expenditures associated with the removal of
polychlorinated biphenyls ("PCB")-contaminated oil from its electrical
equipment. All factors used in estimating the Company's asset-retirement
obligation represent management's best estimate of the fair value of the costs
required to meet existing legislation or regulations. It is reasonably possible
that volumes of contaminated assets, inflation assumptions, cost estimates to
perform the work and the assumed pattern of annual cash flows may differ
significantly from the Company's current assumptions. In addition, in order to
remove certain PCB-contaminated oil, the ability to take maintenance outages in
critical facilities may impact the timing of expenditures. The asset-retirement
obligation may change from period to period because of the changes in the
estimation of these uncertainties. As at June 30, 2010, FortisBC has recognized
approximately $3 million in asset-retirement obligations, which have been
classified on the consolidated balance sheet as long-term other liabilities with
the offset to utility capital assets.
Capitalized Overhead: As required by their regulator, the Terasen Gas companies
capitalize overhead costs not directly attributable to specific capital projects
but related to the overall capital program. Effective January 1, 2010, as
provided in the BCUC-approved NSAs as described above, the percentage for
calculating and capitalizing general overhead costs to utility capital assets at
the Terasen gas companies has changed. The percentage of total general operating
and maintenance costs being allocated and capitalized to utility capital assets
has decreased from 16 per cent to 14 per cent. As a result of this change,
operating expenses increased approximately $1 million for the second quarter and
approximately $2 million year to date over the same periods in 2009, with
corresponding decreases in utility capital assets. The resulting increase in
operating expenses has been approved for recovery in current customer delivery
rates.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A full description of the nature of the regulatory assets and liabilities
is provided in Note 4 to the Corporation's 2009 annual audited consolidated
financial statements.
As at
($ millions) June 30, 2010 December 31, 2009
-------------------------------------------------------------------------
(Note 21)
Regulatory Assets
Future income taxes 567 545
Rate stabilization accounts - Terasen
Gas companies 127 82
Rate stabilization accounts - electric
utilities 63 68
Alberta Electric System Operator
("AESO") charges deferral 59 80
Regulatory other post-employment benefit
("OPEB") plan asset asasset 62 59
Point Lepreau (1) replacement energy
deferral 34 23
Income taxes recoverable on OPEB plans 18 18
Energy management costs 17 14
Deferred development costs for capital 7 7
Southern Crossing Pipeline tax
reassessment 7 7
Deferred pension costs 6 6
Lease costs 6 6
Other regulatory assets 66 55
-------------------------------------------------------------------------
Total Regulatory Assets 1,039 970
Less: Current Portion (256) (223)
-------------------------------------------------------------------------
Long-Term Regulatory Assets 783 747
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
($ millions) June 30, 2010 December 31, 2009
-------------------------------------------------------------------------
(Note 21)
Regulatory Liabilities
Future asset removal and site
restoration provision 329 326
Future income taxes 34 35
Rate stabilization accounts - Terasen
Gas companies 59 44
Rate stabilization accounts - electric
utilities 28 21
Performance-based rate-setting incentive
liabilities 10 15
Unbilled revenue liability 9 10
Unrecognized net gains on disposal of
utility capital assets (1) 8 8
Southern Crossing Pipeline deferral 8 9
Deferred interest 7 7
Other regulatory liabilities 28 22
-------------------------------------------------------------------------
Total Regulatory Liabilities 520 497
Less: Current Portion (46) (53)
-------------------------------------------------------------------------
Long-Term Regulatory Liabilities 474 444
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Relates to amounts accumulated at the Terasen Gas companies prior to January
1, 2010 and, as approved by the regulator, reallocated from accumulated
amortization for future settlement with customers (Note 2 (iii))
6. INVENTORIES
As at
($ millions) June 30, 2010 December 31, 2009
--------------------------------------------------------------------------
Gas in storage 124 159
Materials and supplies 20 19
--------------------------------------------------------------------------
144 178
--------------------------------------------------------------------------
--------------------------------------------------------------------------
During the three and six months ended June 30, 2010, inventories of $191 million
and $496 million, respectively, were expensed and reported in energy supply
costs in the interim consolidated statement of earnings ($156 million and $624
million for the three and six months ended June 30, 2009, respectively).
Inventories expensed to operating expenses were $4 million and $7 million for
the three and six months ended June 30, 2010, respectively ($4 million and $7
million for the three and six months ended June 30, 2009, respectively).
Included in inventories expensed to operating expenses was food and beverage
costs at Fortis Properties of $3 million and $5 million for the three and six
months ended June 30, 2010, respectively ($2 million and $4 million for the
three and six months ended June 30, 2009, respectively).
7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at
($ millions) June 30, 2010 December 31, 2009
-------------------------------------------------------------------------
Long-term debt and capital lease
obligations 5,139 5,331
Long-term classification of committed
credit facilities (Note 19) 422 208
Deferred debt financing costs (38) (39)
-------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,523 5,500
Less: Current installments of long-term
debt and capital lease
obligations (158) (224)
-------------------------------------------------------------------------
5,365 5,276
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital
Securities with proceeds from borrowings under the Corporation's committed
credit facility.
8. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value
As at
Issued and Outstanding June 30, 2010 December 31, 2009
Number of Number of
Shares (in Amount ($ Shares (in Amount($
thousands) millions) thousands) millions)
---------------------------------------------------------------------------
Common shares 172,865 2,537 171,256 2,497
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended June 30, Year-to-Date June 30,
2010 2010
Number of Number of
Shares (in Amount ($ Shares(in Amount ($
thousands) millions) thousands) millions)
---------------------------------------------------------------------------
Balance, beginning of
period 172,169 2,520 171,256 2,497
Consumer Share
Purchase Plan 14 1 28 1
Dividend Reinvestment
Plan 503 13 1,071 28
Employee Share
Purchase Plan 65 1 193 5
Stock Option Plans 114 2 317 6
---------------------------------------------------------------------------
Balance, end of period 172,865 2,537 172,865 2,537
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Earnings per Common Share
The Corporation calculates earnings per common share on the weighted average
number of common shares outstanding.
Diluted earnings per common share are calculated using the treasury stock method
for options and the "if-converted" method for convertible securities.
Earnings per common share were as follows:
Quarter Ended June 30
2010 2009
---------------------------------------------------------------
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 55 172.4 $0.32 53 170.0 $0.31
Effect of
potential
dilutive
securities:
Stock
options - 0.9 - 0.7
Preference
shares
(Note 13) 4 11.9 4 13.9
Convertible
debentures 1 1.4 1 1.4
---------------------------------------------------------------------------
60 186.6 58 186.0
Deduct anti-
dilutive
impacts:
Preference
shares (4) (11.9) (2) (5.3)
Convertible
debentures (1) (1.4) (1) (1.4)
---------------------------------------------------------------------------
Diluted
Earnings
per Common
Share 55 173.3 $0.32 55 179.3 $0.31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-Date June 30
2010 2009
--------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
Basic
Earnings per
Common Share 155 172.0 $0.90 145 169.7 $0.85
Effect of
potential
dilutive
securities:
Stock
options - 0.9 - 0.7
Preference
shares
(Note 13) 8 11.9 8 13.9
Convertible
debentures 1 1.4 1 1.4
---------------------------------------------------------------------------
164 186.2 154 185.7
Deduct anti-
dilutive
impacts:
Convertible
debentures - - (1) (1.4)
---------------------------------------------------------------------------
Diluted
Earnings per
Common Share 164 186.2 $0.88 153 184.3 $0.83
---------------------------------------------------------------------------
---------------------------------------------------------------------------
9. PREFERENCE SHARES
In January 2010, the Corporation issued 10 million Cumulative Five-Year Fixed
Rate Reset First Preference Shares, Series H ("First Preference Shares, Series
H"). The First Preference Shares, Series H were issued at $25.00 per share. The
shares are entitled to receive fixed cumulative preferential cash dividends at a
rate of $1.0625 per share per annum for each year up to but excluding June 1,
2015. For each five-year period after that date, the holders of First Preference
Shares, Series H are entitled to receive reset fixed cumulative preferential
cash dividends. The reset annual dividends per share will be determined by
multiplying $25.00 per share by the annual fixed dividend rate, which is the sum
of the five-year Government of Canada Bond Yield on the applicable reset date
plus 1.45 per cent.
On each First Preference Shares, Series H Conversion Date, being June 1, 2015
and June 1st every five years thereafter, the Corporation has the option to
redeem for cash all or any part of the outstanding First Preference Shares,
Series H, at a price of $25.00 per share plus all accrued and unpaid dividends
up to but excluding the date fixed for redemption. On each Series H Conversion
Date, the holders of First Preference Shares, Series H, have the option to
convert any or all of their First Preference Shares, Series H into an equal
number of cumulative redeemable floating rate First Preference Shares, Series I.
The holders of First Preference Shares, Series I will be entitled to receive
floating rate cumulative preferential cash dividends in the amount per share
determined by multiplying the applicable floating quarterly dividend rate by
$25.00. The floating quarterly dividend rate will be equal to the sum of the
average yield expressed as a percentage per annum on three-month Government of
Canada Treasury Bills plus 1.45 per cent.
On each First Preference Shares, Series I Conversion Date, being June 1, 2020
and June 1st every five years thereafter, the Corporation has the option to
redeem for cash all or any part of the outstanding First Preference Shares,
Series I at a price of $25.00 per share plus all accrued and unpaid dividends up
to but excluding the date fixed for redemption. On any date after June 1, 2015,
that is not a Series I Conversion Date, the Corporation has the option to redeem
for cash all or any part of the outstanding First Preference Shares, Series I at
a price of $25.50 per share plus all accrued and unpaid dividends up to but
excluding the date fixed for redemption. On each Series I Conversion Date, the
holders of First Preference Shares, Series I, have the option to convert any or
all of their First Preference Shares, Series I into an equal number of First
Preference Shares, Series H.
On any Series H Conversion Date, if the Corporation determines that there would
be less than 1 million First Preference Shares, Series H outstanding, such
remaining First Preference Shares, Series H will automatically be converted into
an equal number of First Preference Shares, Series I. On any Series I Conversion
Date, if the Corporation determines that there would be less than 1 million
First Preference Shares, Series I outstanding, such remaining First Preference
Shares, Series I will automatically be converted into an equal number of First
Preference Shares, Series H. However, if such automatic conversions would result
in less than 1 million Series I First Preference Shares or less than 1 million
Series H First Preference Shares outstanding, then no automatic conversion would
take place.
As the First Preference Shares, Series H are not redeemable at the option of the
shareholder, they are classified as equity.
10. STOCK-BASED COMPENSATION PLANS
In January 2010, 24,426 Deferred Share Units were granted to the Corporation's
Board of Directors, representing the equity component of the Directors' annual
compensation and, where opted, their annual retainers in lieu of cash. Each
Deferred Share Unit represents a unit with an underlying value equivalent to the
value of one common share of the Corporation.
In March 2010, 60,000 Performance Share Units were granted to the President and
Chief Executive Officer ("CEO") of the Corporation. Each Performance Share Unit
("PSU") represents a unit with an underlying value equivalent to the value of
one common share of the Corporation. The maturation period of the March 2010 PSU
grant is three years, at which time a cash payment may be made to the President
and CEO after evaluation by the Human Resources Committee of the Board of
Directors of Fortis of the achievement of payment requirements. In May 2010,
21,742 PSUs were paid out to the President and CEO of the Corporation at $27.48
per PSU, for a total of approximately $0.6 million. The payout was made upon the
three-year maturation period in respect of the PSU grant made in May 2007 and
the President and CEO satisfying the payment requirements, as determined by the
Human Resources Committee of the Board of Directors of Fortis.
In March 2010, the Corporation granted 892,744 options to purchase common shares
under its 2006 Stock Option Plan at the five-day volume weighted average trading
price of $27.36 immediately preceding the date of grant. The options vest evenly
over a four-year period on each anniversary of the date of grant. The options
expire seven years after the date of grant. The fair value of each option
granted was $4.41 per option.
The fair value was estimated on the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.66
Expected volatility (%) 25.1
Risk-free interest rate (%) 2.54
Weighted average expected life (years) 4.5
As at June 30, 2010, 5.2 million stock options were outstanding and 3.0 million
stock options were vested.
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, gains and losses on
cash flow hedging activities and gains and losses on discontinued cash flow
hedging activities as described in Note 2 to the Corporation's 2009 annual
audited consolidated financial statements.
Quarter Ended June 30
2010 2009
------------------------------------------------------
Opening Ending Opening Ending
balance Net balance balance Net balance
($ millions) April 1 change June 30 April 1 change June 30
--------------------------------------------------------------------------
Unrealized foreign
currency
translation
(losses) gains, net
of hedging
activities and tax (86) 12 (74) (37) (18) (55)
(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) (5) - (5)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive
(Loss) Income (91) 12 (79) (43) (17) (60)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date June 30
2010 2009
-------------------------------------------------------
Opening Opening
balance Ending balance Ending
January Net balance January Net balance
($ millions) 1 change June 30 1 change June 30
---------------------------------------------------------------------------
Unrealized foreign
currency
translation
(losses) gains, net
of hedging
activities and tax (78) 4 (74) (46) (9) (55)
(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) (5) - (5)
---------------------------------------------------------------------------
Accumulated Other
Comprehensive
(Loss) Income (83) 4 (79) (52) (8) (60)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
12. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans, OPEB plans, defined contribution pension plans
and group registered retirement savings plans ("RRSPs") for its employees. The
cost of providing the defined benefit arrangements was $10 million for the
quarter ended June 30, 2010 ($7 million for the quarter ended June 30, 2009) and
$20 million year-to-date June 30, 2010 ($13 million year-to-date June 30, 2009).
The cost of providing the defined contribution arrangements and group RRSPs for
the quarter ended June 30, 2010 was $3 million ($2 million for the quarter ended
June 30, 2009) and $7 million year-to-date June 30, 2010 ($6 million
year-to-date June 30, 2009).
13. FINANCE CHARGES
Quarter Ended June 30 Year-to-Date June 30
($ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
Interest - Long-term debt
and capital
lease
obligations 88 86 176 170
- Short-term
borrowings and
other 1 2 3 6
Interest charged to
construction (5) (4) (9) (8)
Dividends on preference
shares classified as debt
(Note 8) 4 4 8 8
-------------------------------------------------------------------------
88 88 178 176
-------------------------------------------------------------------------
-------------------------------------------------------------------------
14. CORPORATE TAXES
Corporate taxes differ from the amount that would be expected to be generated by
applying the enacted combined Canadian federal and provincial statutory tax rate
to earnings before corporate taxes. The following is a reconciliation of
consolidated statutory taxes to consolidated effective taxes.
Quarter Ended June 30 Year-to-Date June 30
($ millions, except as
noted) 2010 2009 2010 2009
-------------------------------------------------------------------------
Combined Canadian federal
and provincial statutory
income tax rate 32.0% 33.0% 32.0% 33.0%
-------------------------------------------------------------------------
Statutory income tax rate
applied to earnings
before corporate taxes 26 22 69 63
Preference share dividends 2 2 3 3
Difference between
Canadian statutory rate
and rates applicable to
foreign subsidiaries (5) (4) (7) (7)
Difference in Canadian
provincial statutory
rates applicable to
subsidiaries in different
Canadian jurisdictions (2) (1) (6) (4)
Items capitalized for
accounting but expensed
for income tax purposes (8) (10) (20) (20)
Pension costs 1 - 1 (1)
Other 1 (2) 3 (2)
-------------------------------------------------------------------------
Corporate taxes 15 7 43 32
-------------------------------------------------------------------------
Effective tax rate 18.5% 10.3% 19.9% 16.8%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2010, the Corporation had approximately $143 million (December
31, 2009 - $122 million) in non-capital and capital loss carryforwards, of which
$13 million (December 31, 2009 - $16 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2014 and 2030.
15. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
--------------------------------------------------------
Gas
Uti-
lities Electric Utilities
--------------------------------------------------------
Tera-
sen
Quarter Ended Gas Total
Compa- Elec- Elec-
June 30, 2010 nies - Fortis Fortis NF Other tric tric
Cana-
Cana- Alber- dian Cana- Carib-
($ millions) dian ta BC Power (1) dian bean
--------------------------------------------------------------------------
Revenue 337 92 59 126 75 352 83
Energy supply
costs 191 - 13 75 46 134 47
Operating expenses 65 36 19 15 11 81 11
Amortization 29 25 11 12 6 54 9
--------------------------------------------------------------------------
Operating income 52 31 16 24 12 83 16
Finance charges 29 14 8 9 5 36 4
Corporate taxes
(recoveries) 6 - - 4 3 7 2
--------------------------------------------------------------------------
Net earnings
(loss) 17 17 8 11 4 40 10
Non-controlling
interests - - - - - - 3
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 17 17 8 11 4 40 7
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 143
Identifiable
assets 4,073 1,977 1,189 1,192 630 4,988 828
--------------------------------------------------------------------------
Total assets 4,981 2,204 1,410 1,192 693 5,499 971
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 60 89 37 19 13 158 19
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter Ended
June 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 289 81 55 119 65 320 82
Energy supply
costs 156 - 13 70 40 123 44
Operating expenses 62 31 17 13 9 70 14
Amortization 26 23 9 11 5 48 10
--------------------------------------------------------------------------
Operating income 45 27 16 25 11 79 14
Finance charges 29 13 8 9 4 34 4
Corporate taxes
(recoveries) 2 (3) 1 5 3 6 -
--------------------------------------------------------------------------
Net earnings
(loss) 14 17 7 11 4 39 10
Non-controlling
interests - - - - - - 3
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 14 17 7 11 4 39 7
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 154
Identifiable
assets 3,838 1,767 1,137 1,156 526 4,586 847
--------------------------------------------------------------------------
Total assets 4,746 1,994 1,358 1,156 589 5,097 1,001
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 64 116 27 19 11 173 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-
year term, of the 75 MW of water-right entitlement associated with the
Rankine hydroelectric generating facility at Niagara Falls.
(3) Relates to utility capital assets, including amounts for AESO
transmision capital projects, and to income producing properties and
intangible assets, as reflected in the consolidated statement of cash
flows
NON-REGULATED
----------------------------------
Quarter Ended Inter-
Corpo- seg-
June 30, 2010 Fortis Fortis rate ment
Gene-
ration Proper- and elimi- Conso-
($ millions) (2) ties Other nations lidated
--------------------------------------------------------------------------
Revenue 8 60 9 (13) 836
Energy supply
costs 1 - - (6) 367
Operating expenses 2 39 6 (2) 202
Amortization 1 4 1 - 98
--------------------------------------------------------------------------
Operating income 4 17 2 (5) 169
Finance charges - 6 18 (5) 88
Corporate taxes
(recoveries) 1 3 (4) - 15
--------------------------------------------------------------------------
Net earnings
(loss) 3 8 (12) - 66
Non-controlling
interests - - - - 3
Preference share
dividends - - 8 - 8
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 3 8 (20) - 55
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,562
Identifiable
assets 195 581 122 (20) 10,767
--------------------------------------------------------------------------
Total assets 195 581 122 (20) 12,329
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 2 4 1 - 244
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter Ended
June 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 9 58 7 (9) 756
Energy supply
costs 1 - - (5) 319
Operating expenses 2 38 4 (1) 189
Amortization 2 4 2 - 92
--------------------------------------------------------------------------
Operating income 4 16 1 (3) 156
Finance charges 1 5 18 (3) 88
Corporate taxes
(recoveries) - 3 (4) - 7
--------------------------------------------------------------------------
Net earnings
(loss) 3 8 (13) - 61
Non-controlling
interests - - - - 3
Preference share
dividends - - 5 - 5
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 3 8 (18) - 53
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,573
Identifiable
assets 192 577 141 (17) 10,164
--------------------------------------------------------------------------
Total assets 192 577 141 (17) 11,737
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 4 5 1 - 277
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-
year term, of the 75 MW of water-right entitlement associated with the
Rankine hydroelectric generating facility at Niagara Falls.
(3) Relates to utility capital assets, including amounts for AESO
transmision capital projects, and to income producing properties and
intangible assets, as reflected in the consolidated statement of cash
flows
REGULATED
--------------------------------------------------------
Gas
Uti-
lities Electric Utilities
--------------------------------------------------------
Tera-
sen
Year-to-Date Gas Total
Compa- Elec- Elec-
June 30, 2010 nies - Fortis Fortis NF Other tric tric
Cana- Alber- Cana- Cana- Carib-
($ millions) dian ta BC Power dian(1) dian bean
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 866 180 131 304 157 772 159
Energy supply
costs 496 - 34 206 99 339 92
Operating expenses 135 71 36 31 22 160 23
Amortization 59 49 21 23 11 104 18
--------------------------------------------------------------------------
Operating income 176 60 40 44 25 169 26
Finance charges 56 28 16 18 11 73 9
Corporate taxes
(recoveries) 30 - 2 8 5 15 2
--------------------------------------------------------------------------
Net earnings
(loss) 90 32 22 18 9 81 15
Non-controlling
interests - - - - - - 4
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 90 32 22 18 9 81 11
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 143
Identifiable
assets 4,073 1,977 1,189 1,192 630 4,988 828
--------------------------------------------------------------------------
Total assets 4,981 2,204 1,410 1,192 693 5,499 971
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 110 153 63 36 21 273 36
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date
June 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 958 161 127 288 136 712 165
Energy supply
costs 624 - 35 197 87 319 90
Operating expenses 129 65 34 27 17 143 28
Amortization 51 45 19 22 9 95 20
--------------------------------------------------------------------------
Operating income 154 51 39 42 23 155 27
Finance charges 61 24 15 17 9 65 8
Corporate taxes
(recoveries) 21 (3) 3 8 5 13 1
--------------------------------------------------------------------------
Net earnings
(loss) 72 30 21 17 9 77 18
Non-controlling
interests - - - - - - 5
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 72 30 21 17 9 77 13
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 154
Identifiable
assets 3,838 1,767 1,137 1,156 526 4,586 847
--------------------------------------------------------------------------
Total assets 4,746 1,994 1,358 1,156 589 5,097 1,001
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 114 206 49 32 23 310 50
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-
year term, of the 75 MW of water-right entitlement associated with the
Rankine hydroelectric generating facility at Niagara Falls.
(3) Relates to utility capital assets, including amounts for AESO
transmision capital projects, and to income producing properties and
intangible assets, as reflected in the consolidated statement of cash
flows
NON-REGULATED
---------------------------------
Year-to-Date Inter-
Corpo- seg-
June 30, 2010 Fortis Fortis rate ment
Gene-
ration (2) Proper- and elimina- Conso-
($ millions) ties Other tions lidated
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 13 109 15 (22) 1,912
Energy supply
costs 1 - - (9) 919
Operating expenses 4 75 10 (3) 404
Amortization 2 8 4 - 195
--------------------------------------------------------------------------
Operating income 6 26 1 (10) 394
Finance charges - 12 38 (10) 178
Corporate taxes
(recoveries) 1 4 (9) - 43
--------------------------------------------------------------------------
Net earnings
(loss) 5 10 (28) - 173
Non-controlling
interests - - - - 4
Preference share
dividends - - 14 - 14
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 5 10 (42) - 155
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,562
Identifiable
assets 195 581 122 (20) 10,767
--------------------------------------------------------------------------
Total assets 195 581 122 (20) 12,329
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 3 9 1 - 432
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date
June 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 25 105 13 (20) 1,958
Energy supply
costs 2 - - (9) 1,026
Operating expenses 6 72 7 (3) 382
Amortization 4 8 5 - 183
--------------------------------------------------------------------------
Operating income 13 25 1 (8) 367
Finance charges 2 11 37 (8) 176
Corporate taxes
(recoveries) 2 4 (9) - 32
--------------------------------------------------------------------------
Net earnings
(loss) 9 10 (27) - 159
Non-controlling
interests - - - - 5
Preference share
dividends - - 9 - 9
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 9 10 (36) - 145
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,573
Identifiable
assets 192 577 141 (17) 10,164
--------------------------------------------------------------------------
Total assets 192 577 141 (17) 11,737
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 11 10 1 - 496
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-
year term, of the 75 MW of water-right entitlement associated with the
Rankine hydroelectric generating facility at Niagara Falls.
(3) Relates to utility capital assets, including amounts for AESO
transmision capital projects, and to income producing properties and
intangible assets, as reflected in the consolidated statement of cash
flows
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 six months ended June
30, 2010 and 2009 were as follows.
Significant Inter-Segment
Transactions Quarter Ended June 30 Year-to-date June 30
($ millions) 2010 2009 2010 2009
--------------------------------------------------------------------------
Sales from Fortis Generation
to Regulated Electric
Utilities - Caribbean 5 4 8 8
Sales from Fortis Generation
to Other Canadian Electric
Utilities 1 1 1 1
Sales from Newfoundland Power
to Fortis Properties 1 1 2 2
Inter-segment finance charges
on borrowings from:
Corporate to Regulated
Electric Utilities -
Canadian - - - 1
Corporate to Regulated
Electric Utilities -
Caribbean 1 - 2 1
Corporate to Fortis
Generation 1 1 2 2
Corporate to Fortis
Properties 3 2 5 4
--------------------------------------------------------------------------
16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended June 30 Year-to-date June 30
($ millions) 2010 2009 2010 2009
--------------------------------------------------------------------------
Interest paid 104 99 194 184
Income taxes paid 13 15 37 80
--------------------------------------------------------------------------
--------------------------------------------------------------------------
17. CAPITAL MANAGEMENT
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 to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions
with proceeds from common and preference share issuances. To help ensure access
to capital, the Corporation targets a consolidated long-term capital structure
containing approximately 40 per cent equity, including preference shares, and 60
per cent debt, as well as investment-grade credit ratings.
Each of the Corporation's regulated utilities maintains its own capital
structure in line with the deemed capital structure reflected in the utilities'
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
As at
June 30, 2010 December 31, 2009
($ millions) (%)($ millions) (%)
---------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash)
(1) 5,671 57.7 5,830 60.2
Preference shares (2) 912 9.3 667 6.9
Common shareholders' equity 3,248 33.0 3,193 32.9
---------------------------------------------------------------------------
Total (3) 9,831 100.0 9,690 100.0
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities and
equity
(3) Excludes amounts related to non-controlling interests
Certain of the Corporation's long-term debt obligations have covenants
restricting the issuance of additional debt such that consolidated debt cannot
exceed 70 per cent of the Corporation's consolidated capital structure, as
defined by the long-term debt agreements. As at June 30, 2010, the Corporation
and its subsidiaries, except for certain debt at Belize Electricity and the
Exploits Partnership, as described below, were in compliance with their debt
covenants.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009
Rate Application in June 2008, Belize Electricity does not meet certain debt
covenant financial ratios related to loans with the International Bank for
Reconstruction and Development and the Caribbean Development Bank totalling
approximately $6 million (BZ$11 million) as at June 30, 2010.
As the hydroelectric assets and water rights of the Exploits Partnership had
been provided as security for the Exploits Partnership term loan, the
expropriation of such assets and rights by the Government of Newfoundland and
Labrador constituted an event of default under the loan. The term loan is
without recourse to Fortis and was approximately $58 million as at June 30, 2010
(December 31, 2009 - $59 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan are
being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to the expropriation
matters.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 19.
18. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the six months ended June 30, 2010 in the
designation of the Corporation's financial instruments from that disclosed in
the Corporation's 2009 annual audited consolidated financial statements. The
carrying values of financial instruments included in current assets, current
liabilities, other assets and other liabilities in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or the nature of these instruments. The
carrying and fair values of the Corporation's consolidated long-term debt and
preference shares were as follows:
As at
June 30, 2010 December 31, 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Long-term debt, including
current portion (1) (2) 5,523 6,160 5,502 5,906
Preference shares,
classified as debt (1)
(3) 320 340 320 348
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Carrying value is measured at amortized cost using the effective
interest rate method.
(2) Carrying value as at June 30, 2010 excludes unamortized deferred
financing costs of $38 million (December 31, 2009 - $39 million) and capital
lease obligations of $38 million (December 31, 2009 - $37 million).
(3) Preference shares classified as equity are excluded from the
requirements of the CICA Handbook Section 3855, Financial Instrument,
Recognition and Measurement; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was $595
million as at June 30, 2010 (December 31, 2009 - carrying value $347
million; fair value $356 million).
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a market credit risk
premium equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt prior to maturity, the
fair value estimate does not represent an actual liability and, therefore, does
not include exchange or settlement costs. The fair value of the Corporation's
preference shares is determined using quoted market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes. The following table summarizes the valuation of the Corporation's
consolidated derivative financial instruments.
As at
June 30, 2010 December, 31, 2009
Estimated Estimated
Term Carrying Fair Carrying Fair
to Number Value Value Value Value
Asset Maturity of ($ ($ ($ ($
(Liability) (years) Contracts millions) millions) millions) millions)
---------------------------------------------------------------------------
Interest
rate swap less than
(1) (2) 1 1 - - - -
Foreign
exchange
forward
contracts
(3) (4) 1 to 2 2 1 1 - -
Natural gas
derivatives
: (3) (5)
Swaps and
options Up to 4 193 (156) (156) (119) (119)
Gas
purchase
contract
premiums Up to 3 47 (4) (4) (3) (3)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Interest rate swap contract matures in October 2010.
(2) 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 fair
value measurements are Level 1, based on the three levels that distinguish
the level of pricing observability utilized in measuring fair value.
(3) The fair value measurements are Level 2, based on the three levels that
distinguish the level of pricing observability utilized in measuring fair
value.
(4) The fair values of the foreign exchange forward contracts were recorded
in accounts receivable as at June 30, 2010 and as at December 31, 2009.
(5) The fair values of the natural gas derivatives were recorded in accounts
payable as at June 30, 2010 and as at December 31, 2009.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
19. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit risk Risk that a third party to a financial instrument might fail
to meet its obligations under the terms of the financial
instrument.
Liquidity risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market risk Risk that the fair value or future cash flows of a financial
instrument will fluctuate due to changes in market prices.
The Corporation is exposed to foreign exchange risk,
interest rate risk and commodity price risk.
Credit Risk
For cash and cash equivalents, trade and other accounts receivable, and other
receivables due from customers, the Corporation's credit risk is limited to the
carrying value on the consolidated balance sheet. The Corporation generally has
a large and diversified customer base, which minimizes the concentration of
credit risk. The Corporation and its subsidiaries have various policies to
minimize credit risk, which include requiring customer deposits and credit
checks for certain customers and performing disconnections and/or using
third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its
distribution-service billings being to a relatively small group of retailers
and, as at June 30, 2010, its gross credit risk exposure was approximately $98
million, representing the projected value of retailer billings over a 60-day
period. The Company has reduced its exposure to approximately $3 million by
obtaining from the retailers either a cash deposit, bond, letter of credit, an
investment-grade credit rating from a major rating agency or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The Terasen Gas companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments. The
Terasen Gas companies are also exposed to credit risk on physical off-system
sales. To help mitigate credit risk, the Terasen Gas companies deal with high
credit-quality institutions in accordance with established credit-approval
practices. The counterparties with which the Terasen Gas companies have
significant transactions are A-rated entities or better. The Terasen Gas
companies use netting arrangements to reduce credit risk and net settle payments
with counterparties where net settlement provisions exist.
The aging analysis of the Corporation's consolidated trade and other accounts
receivable, net of an allowance for doubtful accounts of $17 million as at June
30, 2010 (March 31, 2010 - $17 million; December 31, 2009 - $17 million; June
30, 2009 - $18 million), excluding derivative financial instruments recorded in
accounts receivable, was as follows:
($ millions) As at
June 30, March 31, December 31, June 30,
2010 2010 2009 2009
----------------------------------------------------------------------------
Not past due 442 518 527 366
Past due 0-30 days 49 63 52 51
Past due 31-60 days 14 14 8 18
Past due 61 days and over 11 9 8 10
----------------------------------------------------------------------------
516 604 595 445
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2010, other receivables due from customers of $6 million
(included in other assets) will be received over the next five years and,
thereafter, with $1 million expected to be received in year 1, $3 million over
years 2 and 3, $1 million over years 4 and 5 and $1 million due after 5 years.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if
it, or one of its subsidiaries, fails to arrange sufficient and cost-effective
financing to fund, among other things, capital expenditures and the repayment of
maturing debt. The ability to arrange sufficient and cost-effective financing is
subject to numerous factors, including the consolidated results of operations
and financial position of the Corporation and its subsidiaries, conditions in
capital and bank credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing
of acquisitions and for general corporate purposes. Depending on the timing of
cash payments from the subsidiaries, borrowings under the Corporation's
committed credit facility may be required from time to time to support the
servicing of debt and payment of dividends. As at June 30, 2010, average annual
consolidated long-term debt maturities and repayments over the next five years
are expected to be approximately $300 million. The combination of available
credit facilities and relatively low annual debt maturities and repayments
provide the Corporation and its subsidiaries with flexibility in the timing of
access to capital markets.
As at June 30, 2010, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.4 billion was
unused. The credit facilities are syndicated almost entirely with the seven
largest Canadian banks, with no one bank holding more than 25 per cent of these
facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
($ millions) As at
Corporate Regulated Fortis June 30, December
and Other Utilities Properties 2010 31, 2009
------------------------------------------------------------------------
Total credit
facilities 645 1,455 13 2,113 2,153
Credit facilities
utilized:
Short-term
borrowings - (218) (1) (219) (415)
Long-term debt
(including
current portion)
(Note 7) (197) (225) - (422) (208)
Letters of credit
outstanding (1) (111) - (112) (100)
------------------------------------------------------------------------
Credit facilities
unused 447 901 12 1,360 1,430
------------------------------------------------------------------------
------------------------------------------------------------------------
As at June 30, 2010 and December 31, 2009, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In February 2010, Maritime Electric renewed its $50 million unsecured committed
revolving credit facility, which matures annually in March. During the second
quarter of 2010, Maritime Electric increased its unsecured committed revolving
credit facility by $10 million.
In April 2010, FortisBC amended its credit facility agreement obtaining an
extension to the maturity of its $150 million unsecured committed revolving
credit facility with $100 million now maturing in May 2013 and $50 million now
maturing in May 2011.
In May 2010, TGVI entered into a two-year $300 million unsecured committed
revolving credit facility to replace its $350 million credit facility that was
due to mature in January 2011. The terms of the new $300 million credit facility
are substantially similar to the terms of the former $350 million credit
facility, except for an increase in pricing.
In May 2010, Newfoundland Power exercised an option to extend its $100 million
unsecured committed credit facility ("Amended Credit Facility") to August 2013
from August 2011. The Amended Credit Facility agreement is expected to reflect
an increase in pricing but, otherwise, contain substantially similar terms and
conditions as the current credit facility agreement. The amended agreement is
expected to be finalized in August 2010.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
June 30, 2010, the Corporation's credit ratings were as follows.
Standard & Poor's A-(stable) (long-term corporate and unsecured debt credit
rating)
DBRS BBB(high) (unsecured debt credit rating)
The credit ratings reflect the Corporation's low business risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level and the significant
reduction in external debt at Terasen, the Corporation's strong credit metrics,
and the Corporation's demonstrated ability and continued focus of acquiring and
integrating stable regulated utility businesses financed on a conservative
basis.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at June 30, 2010.
Due Due in Due in Due
Financial Liabilities($ within 1 years 2 years 4 after 5
millions) year and 3 and 5 years Total
--------------------------------------------------------------------------
Short-term borrowings 219 - - - 219
Trade and other accounts
payable 645 - - - 645
Natural gas derivatives (1) 102 44 8 - 154
Foreign exchange forward
contracts (2) 12 5 - - 17
Dividends payable 52 - - - 52
Customer deposits (3) 2 2 1 2 7
Long-term debt, including
current portion (4) 156 561 773 4,033 5,523
Interest obligations on long-
term debt 330 641 597 4,576 6,144
Preference shares, classified
as debt - - 123 197 320
Preference share dividend
obligations classified as
finance charges 17 33 21 11 82
--------------------------------------------------------------------------
1,535 1,286 1,523 8,819 13,163
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at June 30, 2010 at $160
million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts receivable at fair value as at June 30, 2010 at $1
million.
(3) Customer deposits were recorded in other liabilities as at June 30,
2010.
(4) Excludes deferred financing costs of $38 million and capital lease
obligations of $38 million
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, self-sustaining foreign
subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar
exchange rate. The Corporation has effectively decreased the above exposure
through the use of US dollar borrowings at the corporate level. The foreign
exchange gain or loss on the translation of US dollar-denominated interest
expense partially offsets the foreign exchange loss or gain on the translation
of the Corporation's foreign subsidiaries' earnings, which are denominated in US
dollars or a currency pegged to the US dollar. Belize Electricity's reporting
currency is the Belizean dollar while the reporting currency of Caribbean
Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and Belize
Electric Company Limited is the US dollar. The Belizean dollar is pegged to the
US dollar at BZ$2.00=US$1.00.
As at June 30, 2010, the Corporation's corporately held US$390 million (December
31, 2009 - US$390 million) long-term debt had been designated as a hedge of a
portion of the Corporation's foreign net investments.
As at June 30, 2010, the Corporation had approximately US$187 million (December
31, 2009 - US$174 million) in foreign net investments remaining to be hedged.
Foreign currency exchange rate fluctuations associated with the translation of
the Corporation's corporately held US dollar borrowings that are designated as
hedges are recorded in other comprehensive income and serve to help offset
unrealized foreign currency exchange gains and losses on the foreign net
investments, which are also recorded in other comprehensive income.
TGI and TGVI's US dollar payments under contracts for the implementation of a
customer information system and the construction of a liquefied natural gas
storage facility, respectively, expose the utilities to fluctuations in the US
dollar-to-Canadian dollar exchange rate. TGI and TGVI have entered into foreign
exchange forward contracts to hedge this exposure and any increase or decrease
in the fair value of the foreign exchange forward contracts is deferred for
recovery from, or refund to, customers in future rates, subject to regulatory
approval.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk
associated with short-term borrowings and floating-rate debt. The Corporation
and its subsidiaries may enter into interest rate swap agreements to help reduce
this risk.
As at June 30, 2010, Fortis Properties was party to one interest rate swap
agreement that effectively fixed the interest rate on variable-rate borrowings.
The Terasen Gas companies and FortisBC have regulatory approval to defer any
increase or decrease in interest expense resulting from fluctuations in interest
rates associated with variable-rate debt for recovery from, or refund to,
customers in future rates.
Commodity Price Risk
The Terasen Gas companies are exposed to commodity price risk associated with
changes in the market price of natural gas. This risk is minimized by entering
into natural gas derivatives that effectively fix the price of natural gas
purchases. The price risk-management strategy of the Terasen Gas companies aims
to improve the likelihood that natural gas prices remain competitive with
electricity rates, temper gas price volatility on customer rates and reduce the
risk of regional price discrepancies. The natural gas derivatives are recorded
on the consolidated balance sheet at fair value and any change in the fair value
is deferred as a regulatory asset or liability, subject to regulatory approval,
for recovery from, or refund to, customers in future rates.
20. CONTINGENT LIABILITIES AND COMMITMENTS
Contingent Liabilities
The Corporation and its subsidiaries are subject to various legal proceedings
and claims associated with ordinary course business operations. Management
believes that the amount of liability, if any, from these actions would not have
a material effect on the Corporation's consolidated financial position or
results of operations. There were no material changes in the Corporation's
contingencies from those disclosed in the Corporation's 2009 annual audited
consolidated financial statements, except as described below.
Terasen
TGI has been disputing a $7 million assessment of British Columbia Social
Services Tax representing additional Provincial Sales Tax and interest on the
Southern Crossing Pipeline, which was completed in 2000. The amount was paid in
full in 2006 to avoid the accrual of further interest and is recorded as a
long-term regulatory deferral asset (Note 5). TGI was successful in its appeal
to the Supreme Court of British Columbia in June 2009.
The Province of British Columbia was granted leave to appeal the decision to the
British Columbia Court of Appeal in October 2009. The hearing took place in May
2010 and the British Columbia Court of Appeal was unanimous in dismissing the
Province of British Columbia's appeal.
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 the rupture in July 2007
of an oil pipeline owned and operated by Kinder Morgan. Terasen has filed a
statement of defence but the claim is in its early stages. During the second
quarter of 2010, Terasen was added as a third party in all of the related
actions and all claims are expected to be tried at the same time. The amount and
outcome of the actions are indeterminable at this time and, accordingly, no
amount has been accrued in the consolidated financial statements.
Maritime Electric
In June 2010, Maritime Electric reached a Settlement Agreement with Canada
Revenue Agency related to the reassessment of the Company's 1997-2004 taxation
years. In the Settlement Agreement, Maritime Electric's treatment of the Energy
Cost Adjustment Mechanism was accepted; however, the reassessments with respect
to customer rebate adjustments and the Company's settlement payment to New
Brunswick Power regarding the write-down of Point Lepreau would stand. The
Company has provided for the entire amount of the reassessment and expects final
reassessments with respect to all affected taxation years by the end of 2010.
Commitments
There were no material changes in the nature and amount of the Corporation's
commitments from the commitments disclosed in the Corporation's 2009 annual
audited consolidated financial statements, except for that described below.
During the first quarter of 2010, FortisBC entered into a contract with Powerex
Corp., a wholly owned subsidiary of BC Hydro, for fixed-price winter capacity
purchases through to February 2016 in an aggregate amount of approximately US$16
million. If FortisBC brings any new resources, such as capital or contractual
projects, on-line prior to the expiry of this agreement, FortisBC may terminate
this contract any time after July 1, 2013 with a minimum of three-months'
written notice to Powerex Corp.
21. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
classifications, the most significant of which related to the Terasen Gas
companies and included an $11 million decrease in long-term regulatory assets, a
$10 million increase in utility capital assets, a $3 million increase in
intangible assets, an $8 million increase in long-term regulatory liabilities,
and a $6 million decrease in long-term future income tax liabilities.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada. With
total assets exceeding $12 billion and fiscal 2009 revenue totalling $3.6
billion, the Corporation serves approximately 2,100,000 gas and electricity
customers. Its regulated holdings include electric distribution utilities in
five Canadian provinces and three Caribbean countries and a natural gas utility
in British Columbia. Fortis owns and operates non-regulated generation assets
across Canada and in Belize and Upper New York State. It also owns and operates
hotels and commercial office and retail space primarily in Atlantic Canada.
Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the
symbol FTS.
Share Transfer Agent and Registrar:
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 2009 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
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