Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved third quarter net
earnings attributable to common equity shareholders of $45 million, or $0.26 per
common share, up $9 million from earnings of $36 million, or $0.21 per common
share, for the third quarter of 2009. Year-to-date net earnings attributable to
common equity shareholders were $200 million, or $1.16 per common share, up $19
million from earnings of $181 million, or $1.06 per common share, for the same
period last year.
Performance for the quarter was driven by the regulated electric utilities in
western Canada and non-regulated hydroelectric generation operations.
Canadian Regulated Electric Utilities contributed earnings of $43 million, up $7
million from the third quarter of 2009, associated with higher contributions
from FortisAlberta, FortisBC and Newfoundland Power. The $4 million increase in
earnings at FortisAlberta was associated with the higher allowed rate of return
on common equity ("ROE"), the higher equity component of total capital
structure, growth in electrical infrastructure investment and an increase in
customers, partially offset by lower net transmission revenue. Earnings at
FortisBC increased $2 million, mainly as a result of the higher allowed ROE and
growth in electrical infrastructure investment, partially offset by a
weather-related decrease in electricity sales. The approximate $1 million
improvement in earnings at Newfoundland Power related to increased electricity
sales and growth in electrical infrastructure investment, partially offset by
higher operating expenses associated with repairing damage from Hurricane Igor
in September 2010.
The Terasen Gas companies incurred a loss of $5 million for the third quarter of
2010 compared to a loss of $3 million for the same quarter last year. The third
quarter is normally a period of lower customer demand due to warmer
temperatures. The higher loss quarter over quarter largely related to increased
operating and maintenance expenses at Terasen Gas Inc. ("TGI") that were
approved by the British Columbia Utilities Commission ("BCUC") as part of the
recent Negotiated Settlement Agreement. The loss in the third quarter of 2010,
however, was reduced by $4 million (after tax) related to the BCUC-approved
reversal of most of the project cost overrun previously expensed in the fourth
quarter of 2009 associated with the conversion of Whistler customer appliances
from propane to natural gas.
Caribbean Regulated Electric Utilities contributed $8 million to earnings, up $1
million from the third quarter of 2009, largely driven by the deferral, for
future collection in customer rates, of previously expensed business taxes at
Belize Electricity.
Non-Regulated Fortis Generation contributed $9 million to earnings, up $5
million from the third quarter of 2009, mainly attributable to increased
hydroelectric production in Belize, driven by higher rainfall and the
commissioning of the Vaca hydroelectric generating facility in March 2010, and
lower finance charges.
In October, Fortis, in partnership with Columbia Power Corporation and Columbia
Basin Trust, concluded definitive agreements to construct a 335-megawatt
hydroelectric generating facility (the "Waneta Expansion") at an estimated cost
of approximately $900 million. The facility is adjacent to the Waneta Dam and
powerhouse facilities on the Pend d'Oreille River, south of Trail, British
Columbia. Fortis owns a 51 per cent interest in the Waneta Expansion and will
operate and maintain the non-regulated investment when the facility comes into
service, which is expected in spring 2015. Construction is anticipated to start
in November 2010.
Fortis Properties delivered earnings of $9 million, consistent with earnings for
the third quarter of 2009.
Corporate and other expenses were $19 million compared to $17 million for the
same quarter last year. The increase in dividends associated with the First
Preference Shares, Series H issued in January 2010 was partially offset by lower
finance charges.
In October, DBRS upgraded the Corporation's debt credit rating to A(low) from
BBB(high). The credit rating upgrade by DBRS was mainly due to the Corporation's
low business-risk profile, reasonable credit metrics, significant reduction in
external debt at Terasen Inc. and the Corporation's demonstrated ability to
acquire and integrate stable utility businesses financed on a conservative
basis. In October, DBRS also upgraded the debt credit rating of FortisBC to
A(low) from BBB(high).
Consolidated capital expenditures, before customer contributions, were $703
million year to date compared to $763 million for the same period last year.
Cash flow from operating activities was $582 million year to date, up $15
million from $567 million for the same period last year.
"Our 2010 capital program is estimated at $1.1 billion, the largest annual
capital program ever undertaken by Fortis," says Stan Marshall, President and
Chief Executive Officer, Fortis Inc. "Planning is also well underway for utility
capital work that will be undertaken in 2011 and beyond to ensure we continue to
meet our customers' needs. Over the next five years our capital program,
including work related to the Waneta Expansion Project, is expected to approach
$5.5 billion, driving growth in earnings and dividends," he explains.
"Fortis continues to pursue acquisitions to build on this organic growth,
focusing on regulated electric and natural gas utilities in the United States
and Canada," Marshall concludes.
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 nine months ended September 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 material 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 implementation of new and final customer rates at FortisAlberta as a result
of the regulatory decision on the 2010 and 2011 revenue requirements
application; the expected increase in the total capital cost of the Fraser River
South Bank South Arm Rehabilitation project at Terasen Gas Inc.; the expected
total capital cost of FortisAlberta's automated meter reading technology
project; the expected total capital cost for the construction of the
335-megawatt Waneta hydroelectric generating facility and its expected
completion date; expected consolidated gross capital expenditures for 2010 and
in total over the five-year period from 2011 through 2015; the expectation that
the Corporation's significant capital program should drive growth in earnings
and dividends; the expected increase in average annual energy production from
the Macal River in Belize by the Vaca hydroelectric generating facility;
expected consolidated long-term debt maturities and repayments on average
annually over the next five years; the expectation of no material adverse credit
rating actions in the near term; expected sources of financing for the
subsidiaries' capital expenditure programs; and except for debt at Belize
Electricity and Exploits River Hydro Partnership ("Exploits Partnership"), the
expectation that the Corporation and its subsidiaries will remain compliant with
debt covenants during 2010.
The forecasts and projections that make up the forward-looking information are
based on assumptions which include, but are not limited to: the receipt of
applicable regulatory approvals and requested rate orders; no significant
operational disruptions or environmental liability due to a catastrophic event
or environmental upset caused by severe weather, other acts of nature or other
major event; the continued ability to maintain the gas and electricity systems
to ensure their continued performance; no significant decline in capital
spending in 2010; no severe and prolonged downturn in economic conditions;
sufficient liquidity and capital resources; the continuation of
regulator-approved mechanisms to flow through the commodity cost of natural gas
and energy supply costs in customer rates; the continued ability to hedge
exposures to fluctuations in interest rates, foreign exchange rates and natural
gas commodity prices; no significant variability in interest rates; no
significant counterparty defaults; the continued competitiveness of natural gas
pricing when compared with electricity and other alternative sources of energy;
the continued availability of natural gas supply; the continued ability to fund
defined benefit pension plans; the absence of significant changes in government
energy plans and environmental laws that may materially affect the operations
and cash flows of the Corporation and its subsidiaries; maintenance of adequate
insurance coverage; the ability to obtain and maintain licences and permits;
retention of existing service areas; no material decrease in market energy sales
prices; maintenance of information technology infrastructure; favourable
relations with First Nations; favourable labour relations; and sufficient human
resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Factors which
could cause results or events to differ from current expectations include, but
are not limited to: regulatory risk; operating and maintenance risks; economic
conditions; capital resources and liquidity risk; capital project budget
overruns and financing risk in the Corporation's non-regulated business; 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;
relations with First Nations; labour relations; and human resources. For
additional information with respect to the Corporation's risk factors, reference
should be made to the Corporation's continuous disclosure materials filed from
time to time with Canadian securities regulatory authorities and to the heading
"Business Risk Management" in the MD&A for the three and nine months ended
September 30, 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 September 30, 2010, the Corporation's electricity
distribution systems met a combined peak demand of approximately 5,034 megawatts
("MW") and its gas distribution system met a peak day demand of 1,006 terajoules
("TJ"). For additional information on the Corporation's business segments, refer
to Note 1 to the Corporation's 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 third quarter and year-to-date periods
ended September 30, 2010 and September 30, 2009 are provided in the following
tables.
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue ($ millions) 720 665 55 2,627 2,623 4
Cash Flow from
Operating
Activities ($
millions) 129 63 66 582 567 15
Net Earnings
Attributable to
Common Equity
Shareholders ($
millions) 45 36 9 200 181 19
Basic Earnings per
Common Share ($) 0.26 0.21 0.05 1.16 1.06 0.10
Diluted Earnings per
Common Share ($) 0.26 0.21 0.05 1.15 1.05 0.10
Weighted Average
Number of Common
Shares Outstanding
(millions) 173.2 170.4 2.8 172.4 170.0 2.4
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Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Regulated Gas
Utilities -
Canadian
Terasen Gas
Companies (1) (5) (3) (2) 85 69 16
--------------------------------------------------------------------------
Regulated Electric
Utilities -
Canadian
FortisAlberta 19 15 4 51 45 6
FortisBC (2) 11 9 2 33 29 4
Newfoundland Power 8 7 1 26 24 2
Other Canadian (3) 5 5 - 14 13 1
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43 36 7 124 111 13
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Regulated Electric -
Caribbean (4) 8 7 1 19 20 (1)
Non-Regulated -
Fortis Generation
(5) 9 4 5 14 14 -
Non-Regulated -
Fortis Properties
(6) 9 9 - 19 19 -
Corporate and Other
(7) (19) (17) (2) (61) (52) (9)
--------------------------------------------------------------------------
Net Earnings
Attributable to
Common Equity
Shareholders 45 36 9 200 181 19
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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 assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York State,
with a combined generating capacity of 139 megawatts ("MW"), mainly
hydroelectric. Results reflect contribution from the Vaca hydroelectric
generating facility in Belize, from March 2010 when the facility was
commissioned. 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
--------------------------------------------------------------------------
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
(TJ) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Core - Residential
and Commercial 12,342 12,050 292 76,600 82,537 (5,937)
Industrial 840 762 78 3,708 4,379 (671)
--------------------------------------------------------------------------
Total Sales
Volumes 13,182 12,812 370 80,308 86,916 (6,608)
Transportation
Volumes 11,383 10,396 987 41,963 43,130 (1,167)
Throughput under
Fixed Revenue
Contracts 2,771 4,601 (1,830) 10,897 12,184 (1,287)
--------------------------------------------------------------------------
Total Gas Volumes 27,336 27,809 (473) 133,168 142,230 (9,062)
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Factors Contributing to Net Negative Quarterly
Gas Volumes Variance
Unfavourable
-- Lower volumes under fixed revenue contracts, due to a large customer
changing its gas supply requirements from peak demand to emergency
demand
Favourable
-- Higher average gas consumption by residential and commercial customers
as a result of cooler temperatures quarter over quarter
-- Higher transportation volumes as a result of the favourable impact of
improving economic conditions in the third quarter of 2010 in the
forestry sector
Factors Contributing to Negative Year-to-Date
Gas Volumes Variance
Unfavourable
-- Lower average gas consumption by residential and commercial customers as
a result of warmer average temperatures in the first quarter of 2010
compared to the same quarter in 2009, partially offset by the impact of
cooler temperatures in the third quarter of 2010 compared to the same
quarter in 2009
-- Lower transportation volumes as a result of warmer average temperatures
period over period and the impact of unfavourable economic conditions
negatively affecting the forestry sector mainly in the first quarter of
2010
-- Lower volumes under fixed revenue contracts, mainly for the reason
discussed above for the quarter
Net customer additions were 3,460 year-to-date 2010 compared to 743 for the same
period last year. Gross customer additions increased period over period due to
increased building activity and customer reconnections were higher period over
period due to cooler temperatures in the third quarter of 2010 compared to the
same quarter last year.
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 and delivery 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.
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 206 208 (2) 1,067 1,166 (99)
Energy Supply Costs 90 98 (8) 586 722 (136)
Operating Expenses 66 60 6 201 189 12
Amortization 27 25 2 81 76 5
Finance Charges 28 30 (2) 84 91 (7)
Corporate Tax
(Recovery) Expense - (2) 2 30 19 11
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Earnings (5) (3) (2) 85 69 16
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Factors Contributing to Net Negative Quarterly
Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
Favourable
-- Higher average gas consumption by residential and commercial customers
-- Increased customer delivery rates, effective January 1, 2010, which
included: (i) 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 for each of
Terasen Gas (Vancouver Island) Inc. ("TGVI") and Terasen Gas Whistler
Inc. ("TGWI") from 9.17 per cent and 8.97 per cent, respectively; (ii)
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;
and (iii) higher forecasted regulatory approved operating expenses and
amortization cost
Factors Contributing to Net Negative Year-to-Date
Revenue Variance
Unfavourable
-- Lower average gas consumption by residential and commercial customers
-- Lower commodity cost of natural gas charged to customers
Favourable
-- The increase in customer delivery rates, effective January 1, 2010
Factors Contributing to Net Negative Quarterly
Earnings Variance
Unfavourable
-- Higher operating expenses driven by: (i) increased labour and employee-
benefit costs; (ii) new initiatives agreed to in the regulator-approved
Negotiated Settlement Agreement ("NSA") related to 2010 and 2011 revenue
requirements resulting in higher planned maintenance and operating
activities in 2010 compared to 2009; (iii) the expensing of asset
removal costs to operating expenses, effective January 1, 2010, as a
result of the NSA; and (iv) lower capitalized overhead costs, due to a
reduction in the capitalization rate, also as a result of the NSA. The
asset removal costs and higher expensed overhead costs were approved for
collection 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 continued investment in utility capital assets. The new
amortization 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 higher effective corporate income tax rate period over period, mainly
due to lower deductions from income for income tax purposes compared to
accounting purposes in 2010 compared to 2009
Favourable
-- The increase in customer delivery rates, effective January 1, 2010
-- The reversal of approximately $5 million ($4 million after tax) of
operating expenses in the third quarter of 2010 related to most of the
project cost overrun previously expensed in the fourth quarter of 2009
associated with the conversion of Whistler customer appliances from
propane to natural gas. During the third quarter of 2010, the Company
received approval from the British Columbia Utilities Commission
("BCUC") to collect most of the additional costs in future customer
rates.
-- Lower finance charges due to lower average credit facility borrowings
period over period
Factors Contributing to Net Positive Year-to-Date
Earnings Variance
Year-to-date 2010, earnings at the Terasen Gas companies were favourably
impacted by the same factors as discussed above for the quarter, partially
offset by the same unfavourable factors also as discussed above for the quarter.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Terasen Gas companies, refer to the
"Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Deliveries
(gigawatt hours
("GWh")) 3,778 3,819 (41) 11,611 11,736 (125)
--------------------------------------------------------------------------
($ millions)
Revenue 109 84 25 289 245 44
Operating Expenses 33 33 - 104 98 6
Amortization 45 25 20 94 70 24
Finance Charges 12 12 - 40 36 4
Corporate Tax
Recovery - (1) 1 - (4) 4
--------------------------------------------------------------------------
Earnings 19 15 4 51 45 6
--------------------------------------------------------------------------
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Factors Contributing to Net Negative Quarterly
Energy Deliveries Variance
Unfavourable
-- Decreased energy deliveries to farm and irrigation, and other industrial
customers, mainly due to lower average consumption resulting from
relatively milder temperatures. Energy deliveries to irrigation
customers were also negatively impacted by continued heavy rainfall
during the third quarter of 2010.
Favourable
-- Increased energy deliveries associated with an increase in the number of
residential and commercial customers
Factors Contributing to Net Negative Year-to-Date
Energy Deliveries Variance
Unfavourable
-- The same factors as discussed above for the quarter
Favourable
-- Increased energy deliveries associated with an increase in the number of
residential, commercial and oil and gas customers
As at September 30, 2010, the total number of customers at FortisAlberta
increased 11,000 year over year.
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. Revenues are a
function of numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Net Positive Quarterly and Year-to-Date
Revenue Variance
Favourable
-- An approximate $22 million and $27 million electricity rate revenue
accrual for the quarter and year to date, respectively, associated with
the impact of the 2010-2011 regulatory rate decision. The rate revenue
accrual was primarily associated with regulatory approved increased
amortization, operating expenses and finance charges and, therefore, did
not have a significant impact on earnings. Approximately $14 million of
the accrual in the third quarter related to the first half of 2010.
-- An interim 7.5 per cent average increase in base customer electricity
distribution rates, effective January 1, 2010
-- A rate revenue accrual of approximately $1 million and $3 million for
the quarter and year to date, 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 year-to-date 2009 and an increase in the equity
component to 41 per cent from 37 per cent as reflected in revenue year-
to-date 2009
-- Customer growth
Collection of the revenue accruals is expected to begin with new final customer
rates and riders, effective January 1, 2011.
Unfavourable
-- Lower net transmission revenue. Effective January 1, 2010, as a result
of the 2010-2011 regulatory rate decision, the impact of volume risk on
transmission costs is deferred to be recovered from, or refunded to,
customers in future rates
-- Lower miscellaneous revenue
Factors Contributing to Net Positive Quarterly and Year-to-Date
Earnings Variance
Favourable
-- The increase in electricity distribution rate revenue related to the
increase in the allowed ROE and equity component, ongoing investment in
electrical infrastructure, customer growth and higher forecasted
regulatory approved expenses
Unfavourable
-- Increased amortization cost associated with higher overall amortization
rates, as approved in the 2010-2011 regulatory rate decision, and
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 operating expenses year to date, mainly due to higher labour
costs and general operating expenses, partially offset by lower
contracted labour costs
-- Increased finance charges year to date, due to higher debt levels in
support of the Company's significant capital expenditure program,
partially offset by lower average credit facility borrowings, increased
capitalized allowance for funds used during construction and the impact
of lower interest rates on the credit facility borrowings
-- Lower net transmission revenue for the reason discussed above
-- Lower corporate tax recovery in 2010, due to lower future income tax
recoveries associated with changes in net customer deferrals subject to
future income tax recoveries and a favourable adjustment to current
income taxes of approximately $2 million during the second quarter of
2009
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisAlberta, refer to the "Regulatory
Highlights" section of this MD&A.
FORTISBC
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 709 720 (11) 2,199 2,298 (99)
--------------------------------------------------------------------------
($ millions)
Revenue 62 57 5 193 184 9
Energy Supply Costs 16 15 1 50 50 -
Operating Expenses 17 16 1 53 51 2
Amortization 10 9 1 31 28 3
Finance Charges 7 8 (1) 23 23 -
Corporate Taxes 1 - 1 3 3 -
--------------------------------------------------------------------------
Earnings 11 9 2 33 29 4
--------------------------------------------------------------------------
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Factors Contributing to Net Negative Quarterly and Year-to-Date
Electricity Sales Variance
Unfavourable
-- Lower average consumption primarily due to unfavourable weather
conditions
Favourable
-- Residential and general service customer growth
-- Increased industrial customer loads
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
-- A 2.9 per cent interim, refundable increase in customer electricity
rates, effective September 1, 2010, as a result of the flow through to
customers of increased power purchase costs charged by BC Hydro
-- Increased performance-based rate-setting ("PBR") incentive adjustments
receivable from customers
-- Higher revenue contribution from non-regulated operating, maintenance
and management services year to date
Unfavourable
-- The 1.5 per cent and 4.3 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 increases in customer electricity rates, effective January 1, 2010
and September 1, 2010
-- Increased PBR incentive adjustments
-- Lower finance charges, primarily due to an increase in capitalized
interest and lower bank fees, partially offset by higher debt levels in
support of the Company's capital expenditure program and higher interest
rates
Unfavourable
-- Higher energy supply costs associated with a higher proportion of
purchased power versus energy generated from Company-owned hydroelectric
generating facilities and the impact of higher average prices for
purchased power, partially offset by the impact of decreased electricity
sales
-- 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
-- Slightly 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, 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 reason discussed above for the
quarter
-- 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) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 916 885 31 3,931 3,825 106
--------------------------------------------------------------------------
($ millions)
Revenue 99 93 6 403 381 22
Energy Supply Costs 50 50 - 256 246 10
Operating Expenses 16 12 4 47 39 8
Amortization 12 11 1 35 34 1
Finance Charges 9 9 - 27 26 1
Corporate Taxes 4 4 - 12 12 -
--------------------------------------------------------------------------
Earnings 8 7 1 26 24 2
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Positive Quarterly and Year-to-Date
Electricity Sales Variance
Favourable
-- Customer growth and higher average consumption
Factors Contributing to 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, ongoing
investment in electrical infrastructure and higher forecasted regulatory
approved expenses, including pension costs
-- A 3.5 per cent and 2.8 per cent increase 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 average 3.5 per cent increase in customer electricity rates,
effective January 1, 2010
-- Increased electricity sales
Unfavourable
-- Additional operating costs of approximately $2 million incurred in the
third quarter of 2010 as a result of Hurricane Igor. The hurricane
affected over half of the Company's service territory on September 21,
2010.
-- Higher pension costs and inflationary and wage increases
-- Higher operating labour costs due to timing. Operating labour costs were
lower than anticipated in the first half of 2010 as better weather
allowed for an earlier start to capital projects.
-- Increased amortization cost associated with continued investment in
utility capital assets
Factors Contributing to Net Positive Year-to-Date
Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
Unfavourable
-- Operating costs associated with Hurricane Igor
-- Higher retirement and severance expenses, increased conservation and
pension costs and wage increases
-- Increased amortization cost for the reason discussed above for the
quarter
-- Higher finance charges associated with interest expense on the $65
million 6.606% bonds issued in May 2009, partially offset by the impact
of lower average credit facility borrowings
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Newfoundland Power, refer to the "Regulatory
Highlights" section of this MD&A.
OTHER CANADIAN ELECTRIC UTILITIES (1)
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 583 514 69 1,750 1,613 137
--------------------------------------------------------------------------
($ millions)
Revenue 87 70 17 244 205 39
Energy Supply Costs 57 46 11 156 133 23
Operating Expenses 11 8 3 33 25 8
Amortization 7 5 2 18 14 4
Finance Charges 5 4 1 16 13 3
Corporate Taxes 2 2 - 7 7 -
--------------------------------------------------------------------------
Earnings 5 5 - 14 13 1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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 39 gigawatt
hours ("GWh") during the third quarter of 2010. Algoma Power was
acquired by FortisOntario in October 2009. Excluding electricity sales
at Algoma Power, electricity sales increased 5.8 per cent quarter over
quarter
-- Higher average consumption mainly due to warmer temperatures experienced
on Prince Edward Island and in Ontario quarter over quarter
Factors Contributing to Net Positive Year-to-date
Electricity Sales Variance
Favourable
-- Electricity sales at Algoma Power of 131 GWh year-to-date 2010.
Excluding electricity sales at Algoma Power, electricity sales increased
less than 1 per cent period over period
-- Higher average consumption mainly due to warmer temperatures experienced
in Ontario during the third quarter of 2010 compared to the same quarter
last year
Unfavourable
-- Lower average consumption on Prince Edward Island mainly due to more
moderate temperatures experienced during the first quarter of 2010,
combined with the impact of conservation initiatives and the economic
downturn, partially offset by higher average consumption on Prince
Edward Island during the third quarter of 2010 for the reason discussed
above for the quarter
Factors Contributing to Positive Quarterly Revenue Variance
Favourable
-- Revenue contribution of approximately $8 million from Algoma Power
during the third quarter of 2010
-- The 5.8 per cent increase in electricity sales, excluding electricity
sales at Algoma Power
-- An increase at Maritime Electric, effective August 1, 2010, 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
Factors Contributing to Positive Year-to-Date Revenue Variance
Favourable
-- Revenue contribution of approximately $26 million from Algoma Power
year-to-date 2010
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- An increase at Maritime Electric, effective August 1, 2010, 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
Factors Contributing to Quarterly and Net Positive Year-to-Date
Earnings Variance
Favourable
-- Lower finance charges at Maritime Electric due to lower short-term
borrowing rates and the repayment of a maturing $15 million first
mortgage bond in May 2010 which carried a 12% interest rate.
-- Algoma Power contributed approximately $0.5 million to earnings year-to-
date 2010
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Maritime Electric and FortisOntario, refer to the
"Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.04 1.10 (0.06) 1.04 1.16 (0.12)
Electricity Sales
(GWh) 318 312 6 880 849 31
--------------------------------------------------------------------------
($ millions)
Revenue 92 90 2 251 255 (4)
Energy Supply Costs 57 52 5 149 142 7
Operating Expenses 12 14 (2) 35 42 (7)
Amortization 9 9 - 27 30 (3)
Finance Charges 4 4 - 13 12 1
Corporate Tax
(Recovery) Expense (1) - (1) 1 1 -
--------------------------------------------------------------------------
11 11 - 26 28 (2)
Non-Controlling
Interests 3 4 (1) 7 8 (1)
--------------------------------------------------------------------------
Earnings 8 7 1 19 20 (1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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 Net Positive Quarterly
Electricity Sales Variance
Favorable
-- Higher average temperatures experienced in Belize and the Turks and
Caicos Islands period over period, which increased air-conditioning load
-- Customer growth at Belize Electricity and Caribbean Utilities
-- Incremental load associated with 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 July 2010, Fortis Turks and Caicos achieved new record peak load of
31 MW
Unfavourable
-- Lower average temperatures and higher rainfall on Grand Cayman quarter
over quarter, which decreased air-conditioning load
-- Reduced residential customer base at Fortis Turks and Caicos, due to
expatriate workers, previously employed in the construction sector, now
leaving the Islands
-- Continued weak economic conditions tempering growth mainly at Caribbean
Utilities
Factors Contributing to Net Positive Year-to-Date
Electricity Sales Variance
Favourable
-- The same factors as discussed above for the quarter
-- Higher average temperatures experienced on Grand Cayman period over
period
Unfavourable
-- Reduced residential customer base at Fortis Turks and Caicos, for the
reason discussed above for the quarter
-- Continued weak economic conditions tempering growth mainly at Caribbean
Utilities
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 1.9 per cent overall increase in electricity sales
Unfavourable
-- Approximately $5 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 $29 million associated with unfavourable foreign currency
translation
-- Revenue during the first quarter of 2009 included approximately $1
million associated with a favourable court of 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
-- A 2.4 per cent increase in basic customer electricity rates at Caribbean
Utilities, effective June 1, 2009
-- A 3.7 per cent overall increase in electricity sales
Factors Contributing to Net Positive Quarterly Earnings Variance
Favourable
-- The deferral during the third quarter of 2010, for future collection in
customer rates, of previously expensed business taxes at Belize
Electricity of approximately $1 million
-- Lower operating expenses, excluding the impact of foreign exchange, due
to a delay in Caribbean Utilities' maintenance program resulting from
increased concentration on the utility's capital program, and lower
provision for bad debts at Fortis Turks and Caicos, partially offset by
increased legal, employee and contractor costs at Belize Electricity
-- Increased electricity sales
Unfavourable
-- Approximately $0.5 million associated with unfavourable foreign currency
translation
-- The favourable impact on energy supply costs during the third quarter of
2009, due to a change in the methodology for calculating the cost of
fuel recoverable from customers at Fortis Turks and Caicos
Factors Contributing to Net Negative Year-to-Date Earnings Variance
Unfavourable
-- Approximately $2.5 million associated with unfavourable foreign currency
translation
-- 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 2009 and July 2009 at Caribbean Utilities, and lower
capitalized allowance for funds used during construction, combined with
higher interest expense on regulatory liabilities at Belize Electricity
-- The favourable impact on energy supply costs year-to-date 2009 at Fortis
Turks and Caicos, for the reason discussed above for the quarter
-- Revenue during the first quarter of 2009 included approximately $1
million associated with the favourable court of appeal judgment at
Fortis Turks and Caicos.
Favourable
-- Lower operating expenses, excluding the impact of foreign exchange, for
the reasons discussed above for the quarter, combined with higher
capitalized general and administrative expenses and efforts to control
discretionary costs at Caribbean Utilities, partially offset by
increased legal, employee and contractor costs at Belize Electricity
-- Increased electricity sales
-- The 2.4 per cent increase in basic customer electricity rates at
Caribbean Utilities, effective June 1, 2009
For additional information on the nature of regulation and material regulatory
decisions and applications pertaining to Belize Electricity, Caribbean Utilities
and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of
this MD&A.
NON-REGULATED - FORTIS GENERATION (1)
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-date
Periods Ended
September 30 2010(2) 2009 Variance 2010(2) 2009 (3) Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Sales (GWh) 134 98 36 290 496 (206)
--------------------------------------------------------------------------
($ millions)
Revenue 13 8 5 26 34 (8)
Energy Supply Costs - - - 1 2 (1)
Operating Expenses 2 2 - 6 8 (2)
Amortization 1 1 - 3 4 (1)
Finance Charges - 1 (1) - 3 (3)
Corporate Taxes 1 - 1 2 2 -
--------------------------------------------------------------------------
9 4 5 14 15 (1)
Non-Controlling
Interests - - - - 1 (1)
--------------------------------------------------------------------------
Earnings 9 4 5 14 14 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Includes the results of non-regulated assets in Belize, Ontario,
central Newfoundland, British Columbia and Upper New York State
(2)Results reflect contribution from the Vaca hydroelectric generating
facility in Belize, from March 2010 when the facility was commissioned.
(3)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 Positive Quarterly
Energy Sales Variance
Favourable
-- Higher rainfall and the commissioning of the Vaca hydroelectric
generating facility in Belize 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 35 GWh for the
third quarter of 2010.
Unfavourable
-- Lower production in Upper New York State due to lower rainfall
Factors Contributing to Net Negative 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 year-to-date
2009 included approximately 215 GWh 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 time the consolidation method of accounting for these
operations was discontinued as a consequence of 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 same factors as discussed above for the quarter. Production by the
Vaca hydroelectric generating facility was 55 GWh year-to-date 2010.
Factors Contributing to Positive Quarterly
Revenue Variance
Favourable
-- Higher production in Belize
Factors Contributing to Net Negative 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 on February 12, 2009
-- Approximately $2 million unfavourable foreign exchange associated with
the translation of US dollar-denominated revenue, due to the weakening
of the US dollar relative to the Canadian dollar period over period
Favourable
-- Higher production in Belize
Factors Contributing to Net Positive Quarterly Earnings Variance
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 during construction ended.
Unfavourable
-- Approximately $1 million associated with unfavourable foreign currency
translation
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
Unfavourable
-- The expiration of the Rankine water rights. Earnings' contribution
associated with the Rankine hydroelectric generating facility was
approximately $3.5 million year-to-date 2009.
-- Approximately $2 million associated with unfavourable foreign currency
translation
NON-REGULATED - FORTIS PROPERTIES
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Hospitality
Revenue 44 44 - 120 117 3
Real Estate
Revenue 16 16 - 49 48 1
--------------------------------------------------------------------------
Total Revenue 60 60 - 169 165 4
Operating Expenses 38 37 1 113 109 4
Amortization 5 4 1 13 12 1
Finance Charges 6 6 - 18 17 1
Corporate Taxes 2 4 (2) 6 8 (2)
--------------------------------------------------------------------------
Earnings 9 9 - 19 19 -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Quarterly Revenue Variance
Favourable
-- Higher revenue contribution from hotel properties in central Canada,
offset by lower revenue contribution from hotel properties in western
and Atlantic Canada
-- A 0.6 per cent increase in revenue per available room ("RevPAR") at the
Hospitality Division to $89.54 for the third quarter of 2010 from $89.02
for the same quarter in 2009. RevPAR increased due to an overall 0.9 per
cent increase in average room rates, partially offset by an overall 0.3
per cent decrease in hotel occupancy. Average room rates at operations
in western and central Canada increased, while rates at operations in
Atlantic Canada decreased. Hotel occupancy at operations in western
Canada decreased, while occupancy at operations in central and Atlantic
Canada increased.
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division to 93.7 per
cent as at September 30, 2010 from 96.2 per cent as at September 30,
2009, driven by operations in Newfoundland and New Brunswick
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 higher revenue contribution from hotel
properties in Atlantic and central Canada, partially offset by lower
revenue contribution from hotel properties in western Canada
-- Revenue growth in the Atlantic Canada region of the Real Estate
Division, with the most significant increase being in Nova Scotia,
mainly due to rent increases
-- A $0.2 million gain on sale of land in central Newfoundland during the
first quarter of 2010
Unfavourable
-- A 0.4 per cent decrease in RevPAR at the Hospitality Division to $78.89
year-to-date 2010 from $79.19 year-to-date 2009. RevPAR decreased due to
an overall 2.1 per cent decrease in hotel occupancy, partially offset by
an overall 1.7 per cent increase in average room rates. Hotel occupancy
at operations in western Canada decreased, while occupancy at operations
in central and Atlantic Canada increased. Average room rates at
operations in western and Atlantic Canada increased, while rates at
operations in central Canada decreased.
-- Decreased occupancy rate at the Real Estate Division, as discussed above
for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- The impact of a lower effective income tax rate, due to higher
deductions taken for tax purposes compared to accounting purposes
combined with a lower statutory income tax rate
Unfavourable
-- Lower occupancies at hotel operations in western Canada, driven by the
continued impact of the economic downturn
-- Higher amortization cost, mainly due to capital expansions and
improvements
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factor as discussed above for the quarter
-- Contribution from the Holiday Inn Select Windsor from April 2009
Unfavourable
-- The same factors as discussed above for the quarter
-- Increased finance charges due to higher debt levels and interest rates
CORPORATE AND OTHER (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 8 8 - 23 21 2
Operating Expenses 3 2 1 13 9 4
Amortization 1 2 (1) 5 6 (1)
Finance Charges
(2) 20 21 (1) 58 58 -
Corporate Tax
Recovery (4) (5) 1 (13) (14) 1
--------------------------------------------------------------------------
(12) (12) - (40) (38) (2)
Preference Share
Dividends 7 5 2 21 14 7
--------------------------------------------------------------------------
Net Corporate and
Other Expenses (19) (17) (2) (61) (52) (9)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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
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.
Favourable
-- Lower finance charges, mainly due to the repayment of higher interest-
bearing debt in 2010, partially offset by the impact of higher average
credit facility borrowings. In April 2010, Terasen redeemed its $125
million 8.0% Capital Securities with proceeds from borrowings under the
Corporation's committed credit facility.
Factors Contributing to Net Negative Year-to-Date
Net Corporate and Other Expenses Variance
Unfavourable
-- Higher preference share dividends, as discussed above for the quarter
-- 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, were partially offset by the repayment of higher interest-
bearing debt in 2010.
Favourable
-- Increased revenue due to interest income on higher inter-company lending
to Fortis Properties to finance the Company's maturing external debt
-- A favourable foreign exchange impact of approximately $2 million
associated with the translation of US dollar-denominated interest
expense, due to the weakening of the US dollar relative to the Canadian
dollar period over period
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
are summarized as follows:
Nature of Regulation
--------------------------------------------------------------------------
Allowed
Common
Regulated Regulatory Equity Supportive
Utility Authority (%) Allowed Returns (%) Features
---------------------------------------
Future or
Historical Test
Year Used to Set
2008 2009 2010 Customer Rates
--------------------------------------------------------------------------
Cost of Service
ROE ("COS")/ROE
---------------------
TGI BCUC 40 (1) 8.62 8.47 9.50 TGI: Prior to
(2) January 1, 2010,
/9.50 50/50 sharing of
(3) 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 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
--------------------------------------------------------------------------
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 +/- 50
Board of bps bps bps ROE for 2010
Commissioners established by
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
--------------------------------------------------------------------------
ROE
---------------------
FortisOntario Ontario 40 (5) 9.00 8.01 8.01 Canadian Niagara
Energy Board Power - COS/ROE
("OEB")
Canadian Algoma Power -
Niagara Power COS/ROE and
subject to Rural
Rate Protection
Subsidy program
Algoma Power 50 N/A 8.57 8.57/ Cornwall
9.85 Electric - Price
Franchise (6) cap with
Agreement commodity cost
Cornwall flow through
Electric
----------------
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
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 COS/ROA
and Caicos make annual (9) (9) (9)
filings with If the actual
the ROA is lower
Government than the allowed
ROA, due to
additional costs
resulting from a
hurricane or
other event, the
Company may
apply for an
increase in
customer rates
in the following
year.
----------------
Future Test Year
--------------------------------------------------------------------------
(1)Effective January 1, 2010. For 2008 and 2009, the allowed deemed equity
component of the capital structure was 35 per cent.
(2)Pre-July 1, 2009
(3)Effective July 1, 2009
(4)Effective January 1, 2009. For 2008, the allowed deemed equity
component of the capital structure was 37 per cent.
(5)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
TGWI 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. 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.
Effective October 2010, commodity rates remained
unchanged for all regions.
- 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 for each
of TGVI and TGWI, effective July 1, 2009, from 9.17 per
cent and 8.97 per cent, respectively. 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 at TGI of the approved NSA, the
increase in the allowed ROE, the higher equity
component and the increase in mid-stream costs was in
an increase in customer rates of approximately 10 per
cent, effective January 1, 2010, for residential
customers in the Lower Mainland, Fraser Valley,
Interior, North and Kootenay service areas. 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.
- TGI, TGVI and TGWI are considering an amalgamation of
the three companies. An amalgamation would require an
application to be approved by the BCUC and consent of
the Government of British Columbia. While a decision
to proceed with an amalgamation has not yet been made,
the Terasen Gas companies are contemplating bringing
forth an application during 2011.
--------------------------------------------------------------------------
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 electrical
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.
- In August 2010, FortisBC received BCUC approval for a
2.9 per cent interim, refundable increase in customer
rates, effective September 2010. The increase was due
to higher power purchase costs being charged to the
Company by BC Hydro.
- In October 2010, FortisBC filed its Preliminary 2011
Revenue Requirements Application requesting a general
customer electricity rate increase of 5.9 per cent,
effective January 1, 2011. The requested rate increase
is due to the Company's ongoing investment in
electrical infrastructure and increasing power
purchases driven by customer growth and increased
electricity demand.
- In November 2010, FortisBC received Board of
Directors approval to enter into an agreement ("the
Waneta Expansion Capacity Agreement") to purchase
capacity output from a 335-MW hydroelectric generating
facility (the "Waneta Expansion"). The Waneta Expansion
Capacity Agreement was accepted by the BCUC in
September 2010 and will allow FortisBC to purchase
capacity for 40 years, commencing in 2015. For further
information on the Waneta Expansion, refer to the
"Subsequent Events" section of this MD&A.
--------------------------------------------------------------------------
FortisAlberta - In November 2009, the AUC issued its decision on the
2009 Generic Cost of Capital Proceeding ("2009 GCOC
Decision") establishing a generic allowed ROE of 9.00
per cent for 2009, 2010, and for 2011 on an interim
basis, for all Alberta utilities regulated by the AUC.
The allowed ROE of 9.00 per cent is up from the interim
allowed ROE of 8.51 per cent for 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.
- In July 2010, the AUC issued a decision on the
Company's comprehensive two-year Distribution Tariff
Application ("DTA") for 2010 and 2011, which was
originally filed in June 2009. The Company has
reflected the impact of the decision, retroactive from
January 1, 2010, in its third quarter results and has
accrued the increased revenue requirements for
collection in customer base distribution electricity
rates and rate riders expected to begin effective
January 1, 2011 for billing implementation. The
resulting required increase in customer rates reflects
the Company's ongoing investment in electrical
infrastructure, to support customer growth and to
maintain and upgrade the electricity system, higher
forecasted regulatory approved expenses and the impact
of the 2009 GCOC Decision. There was no material impact
on third quarter 2010 earnings associated with
recording the retroactive effects of the rate decision
pertaining to the first half of 2010. As normal
course, the Company submitted a Compliance Filing in
August 2010 in relation to the AUC decision, requesting
forecast revenue requirements of $347 million for 2010
and $371 million for 2011. Also included in the
Compliance Filing was: (i) forecast operating expenses
of $141 million for each of 2010 and 2011; (ii)
forecast amortization cost of $125 million for 2010 and
$142 million for 2011; (iii) forecast capital
expenditures of $290 million for 2010 and $246 million
for 2011 and, in addition, forecast Alberta Electric
System Operator ("AESO") transmission capital
contributions of $54 million for 2010 and $42 million
for 2011; and (iv) forecast mid-year rate base of
$1,570 million for 2010 and $1,735 million for 2011.
Included in the Compliance Filing, as a placeholder,
was a successful outcome of the Company's Review and
Variance Application and Leave to Appeal, as further
discussed below.
- In its DTA for 2010 and 2011, FortisAlberta had
requested an update in the forecast capital cost of its
Automatic Meter Reading ("AMR") Project, bringing the
total project cost to $126 million (excluding the cost
of the pilot program of $15 million), up from an
original project cost of $104 million. The AUC reached
the conclusion, however, that the capital cost of the
AMR Project of $104 million (excluding the pilot
program) had formed part of the Company's 2008/2009
NSA, which had been approved in 2008. The Company has
filed a Review and Variance Application with the AUC
and a Leave to Appeal with the Alberta Court of Queen's
Bench regarding this conclusion.
- 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, ongoing investment in electrical
infrastructure and higher forecasted regulatory
approved 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. The 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 benefit ("OPEB") costs. The
Company recommended 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
associated with OPEBs 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,
net of customer contributions.
- 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.
- In August 2010, Newfoundland Power filed an
application with the PUB requesting the deferred
recovery of expected increased costs in 2011 of $2.4
million, due to expiring regulatory amortizations.
- Newfoundland Power is currently assessing the
necessary regulatory action to respond to the
additional costs resulting from Hurricane Igor.
--------------------------------------------------------------------------
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 the extended life of the unit; and (iii)
an allowed ROE of 9.75 per cent for both 2010 and 2011,
unchanged from 2009.
- In July 2010, Maritime Electric filed its 2011
Capital Budget requesting approval for $23 million in
capital expenditures. A decision is expected from IRAC
during the fourth quarter of 2010.
- In August 2010, the Company filed a Demand-Side
Management Plan for 2011-2015 outlining the Company's
plan to achieve energy peak reduction required under
the Renewable Energy Act.
- The refurbishment of Point Lepreau continues to be
delayed and the station is not expected to return into
service until fall 2012. The Government of New
Brunswick has stated that it will be seeking mediation
with the Government of Canada for the significant
incremental cost of replacement energy during the
refurbishment.
--------------------------------------------------------------------------
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 proposed an approximate
14.6 per cent increase in electricity distribution
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.
- During the third quarter of 2010, Algoma Power
participated in a settlement conference and submitted a
settlement agreement to the OEB for electricity
distribution rates, effective December 1, 2010, based
on a 2011 test year. The settlement agreement
effectively yields approximately 97 per cent of the
requested 2011 revenue requirement. A decision on the
settlement agreement is expected from the OEB in the
fourth quarter of 2010.
- In August 2010, FortisOntario notified the OEB that
it would not be filing cost of service applications for
2011 electricity distribution rates for Fort Erie,
Gananoque and Port Colborne. Rather, the Company has
filed Third-Generation IRM electricity distribution
rate applications for rates to be effective May 1, 2011
for these areas. FortisOntario does, however, expect
to file cost of service applications in April 2011 for
harmonized electricity distribution rates for Fort Erie
and Gananoque and rates for Port Colborne, effective
January 1, 2012, using a 2012 future test year.
--------------------------------------------------------------------------
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 (the "June 2008 Final Decision") 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.
- The evidentiary portion of the trial of Belize
Electricity's appeal of the PUC's June 2008 Final
Decision was heard in October 2010. Closing arguments
are expected to be completed in early December 2010 so
that the case will be closed pending judgment of the
Court.
--------------------------------------------------------------------------
Caribbean - In February 2010, the ERA approved Caribbean
Utilities Utilities' 2010 Capital Investment Plan ("CIP") at
US$21 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 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.
--------------------------------------------------------------------------
Fortis Turks and - In March 2010, Fortis Turks and Caicos submitted its
Caicos 2009 annual regulatory filing outlining the Company's
performance in 2009 and its capital expansion plans for
2010.
- In March 2010, Fortis Turks and Caicos filed an
Electricity Rate Review with the Ministry of Works,
Housing and Utilities of the Government of the Turks
and Caicos Islands in accordance with Section 34 of the
Electricity Ordinance. The filing 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 September 30, 2010 and December 31, 2009.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between September 30, 2010 and December 31, 2009
------------------------------------------------------------------------
Balance Sheet Increase/
Account (Decrease)($
millions) Explanation
------------------------------------------------------------------------
Accounts (152) The decrease was primarily due to the
receivable impact of a seasonal decrease in sales,
driven by the Terasen Gas companies and
Newfoundland Power, partially offset by
higher revenue accruals at FortisAlberta.
------------------------------------------------------------------------
Regulatory 158 The increase was driven by deferrals at
assets - the Terasen Gas companies associated with:
current and (i) an $82 million change in the fair
long-term market value of the natural gas
derivatives; and (ii) the drawdown of the
Commodity Cost Reconciliation Account and
the Gas Cost Variance Account at TGI and
TGVI, respectively, 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.
------------------------------------------------------------------------
Inventories 24 The increase was driven by the normal
seasonal increase of gas in storage at the
Terasen Gas companies, partially offset by
lower natural gas commodity prices.
------------------------------------------------------------------------
Utility 350 The increase primarily related to $672
capital assets million invested in electricity and gas
systems, partially offset by amortization
and customer contributions year-to-date
2010, and the impact of foreign exchange
on the translation of foreign currency-
denominated utility capital assets.
------------------------------------------------------------------------
Short-term (74) The decrease was driven by the
borrowings reclassification of $70 million borrowed
under TGVI's credit facility to long-term
debt upon renegotiation of the Company's
committed credit facility, the repayment
of short-term borrowings by TGI with
proceeds from an equity injection from
Fortis, and lower borrowings at the
Terasen Gas companies due to seasonality
of its operations. The decrease was
partially offset by higher borrowings at
Maritime Electric to finance $15 million
of maturing long-term debt, and at
Caribbean Utilities to finance capital
expenditures.
------------------------------------------------------------------------
Accounts (26) The decrease was driven by lower amounts
payable and owing for purchased natural gas at the
accrued Terasen Gas companies and purchased power
charges at Newfoundland Power, due to seasonality
of operations and lower commodity cost of
natural gas at the Terasen Gas companies,
and the timing of payment of property
taxes and franchise fees at the Terasen
Gas companies. The decrease was partially
offset by an $82 million change in the
fair market value of the natural gas
derivatives at the Terasen Gas companies.
------------------------------------------------------------------------
Dividends 49 The increase was due to the timing of the
payable declaration of common share dividends for
the first quarter of 2010.
------------------------------------------------------------------------
Regulatory 23 The increase was mainly due to an increase
liabilities - in the Rate Stabilization Deferral Account
current and at TGVI, reflecting the accumulation of
long-term over-recovered costs of providing service
to customers year-to-date 2010, an
increase in the provision for asset
removal and site restoration costs at
FortisAlberta and an increase in the Rate
Stabilization Account at Belize
Electricity, partially offset by a
reduction in the Revenue Stabilization
Adjustment Mechanism account at TGI, as
natural gas consumption volumes were lower
than forecast year-to-date 2010.
------------------------------------------------------------------------
Long-term debt 34 The increase was driven by a net $193
and capital million increase in committed credit
lease facility borrowings classified as long-
obligations term and the reclassification of $70
(including million of committed credit facility
current borrowings by TGVI from short-term
portion) borrowings. 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, the redemption of
the $125 million 8.0% Capital Securities
at Terasen with proceeds from borrowings
under the Corporation's committed credit
facility, the repayment of approximately
$47 million of maturing debt at Fortis
Properties with proceeds from borrowings
under the Corporation's committed credit
facility, and the impact of foreign
exchange on the translation of foreign
currency-denominated long-term debt.
------------------------------------------------------------------------
Future income 27 The increase was driven by tax timing
tax differences related to capital
liabilities - expenditures at FortisAlberta and
current and FortisBC.
long-term
------------------------------------------------------------------------
Shareholders' 306 The increase was driven by the issuance of
equity $250 million five-year fixed rate reset
preference shares in January 2010.
The remainder of the increase was due to
net earnings attributable to common equity
shareholders year-to-date 2010, less
common share dividends, and the issuance
of common shares under the Corporation's
share purchase, dividend reinvestment and
stock option plans.
------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
Summary of Consolidated Cash Flows: The table below outlines the Corporation's
consolidated sources and uses of cash for the three and nine months ended
September 30, 2010, as compared to the same periods in 2009, followed by a
discussion of the nature of the variances in cash flows.
--------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Cash, Beginning of
Period 71 137 (66) 85 66 19
Cash Provided by
(Used in):
Operating
Activities 129 63 66 582 567 15
Investing
Activities (253) (251) (2) (658) (733) 75
Financing
Activities 117 159 (42) 55 209 (154)
Effect of Exchange
Rate Changes on
Cash and Cash
Equivalents - (2) 2 - (3) 3
--------------------------------------------------------------------------
Cash, End of Period 64 106 (42) 64 106 (42)
--------------------------------------------------------------------------
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $66 million higher quarter over quarter, mainly due to
higher earnings, the collection from customers of increased amortization costs
driven by the Terasen Gas companies and favourable 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 quarter over
quarter and the differing effects of seasonality.
Cash flow from operating activities, after working capital adjustments, was $15
million higher year to date compared to the same period in 2009. The favourable
impact of: (i) higher earnings; (ii) the collection from customers of increased
amortization costs driven by the Terasen Gas companies; (iii) favourable changes
in the AESO charges deferral account at FortisAlberta; (iv) the timing of
property tax and other payments at FortisBC; (v) a decrease in the amount of
corporate taxes paid at the Terasen Gas companies and Newfoundland Power; and
(vi) the timing of the declaration of common share dividends for the first
quarter of 2010 were partially offset by otherwise unfavourable working capital
changes at the Terasen Gas companies. The unfavourable working capital changes
were due to 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.
Investing Activities: Cash used in investing activities was comparable quarter
over quarter. Cash used in investing activities was $75 million lower year to
date compared to the same period in 2009, 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 Regulated Electric Utilities - Caribbean were largely offset by
higher gross capital expenditures at FortisBC.
Financing Activities: Cash provided by financing activities was $42 million
lower quarter over quarter, driven by: (i) lower proceeds from long-term debt;
(ii) lower net proceeds from short-term borrowings; and (iii) higher common and
preference share dividends, partially offset by: (i) higher proceeds from net
borrowings under committed credit facilities; (ii) lower repayments of long-term
debt; and (iii) higher proceeds from the issuance of common shares.
Cash provided by financing activities was $154 million lower year to date
compared to the same period in 2009, driven by: (i) lower proceeds from
long-term debt; (ii) higher repayments of long-term debt; and (iii) higher
common and preference share dividends, partially offset by: (i) higher proceeds
from net borrowings under committed credit facilities; (ii) lower net repayments
of short-term borrowings; and (iii) higher proceeds from the issuance of
preference and common shares.
Net proceeds from short-term borrowings were $46 million lower quarter over
quarter and net repayments of short-term borrowings were $67 million lower year
to date compared to the same period in 2009. The changes in short-term
borrowings mainly related to the Terasen Gas companies associated with working
capital and capital expenditure requirements, and repayments with cash from
operations and, in January 2010, with proceeds from an equity injection by the
Corporation.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease obligations and net borrowings (repayments) under committed
credit facilities for the quarter and year to date compared to the same periods
last year are summarized in the following tables.
--------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Terasen Gas Companies - - - - 99 (1) (99)
FortisAlberta - - - - 99 (2) (99)
FortisBC - - - - 104 (3) (104)
Newfoundland Power - - - - 65 (4) (65)
Caribbean Utilities - 11 (5) (11) - 45 (5) (45)
Corporate - 198 (6) (198) - 198 (6) (198)
--------------------------------------------------------------------------
Total - 209 (209) - 610 (610)
--------------------------------------------------------------------------
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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 to 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 and July 2009, 15-year US$30 million and US$10 million,
respectively, 7.50% unsecured notes. The net proceeds were used to repay
short-term borrowings and finance capital expenditures.
(6)Issued July 2009, 30-year $200 million 6.51% unsecured debentures. The
net proceeds were used to repay, in full, the indebtedness outstanding
under the Corporation's committed credit facility and for general
corporate purposes.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
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Terasen Gas
Companies - - - (1) (63) 62
FortisBC - (51) 51 (1) (51) 50
Maritime Electric - - - (15) - (15)
Caribbean Utilities - - - (15) (16) 1
Fortis Properties (1) (6) 5 (53) (11) (42)
Corporate - Terasen - - - (125) (1) - (125)
Other (2) - (2) (5) (7) 2
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Total (3) (57) 54 (215) (148) (67)
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(1)In April 2010, Terasen redeemed in full for cash its $125 million 8.0%
Capital Securities with proceeds from borrowings under the Corporation's
committed credit facility.
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Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended
September 30 Quarter Year-to-date
($ millions) 2010 2009 Variance 2010 2009 Variance
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FortisAlberta 22 36 (14) 82 37 45
FortisBC 15 2 13 27 (29) 56
Newfoundland Power (18) (5) (13) (5) (32) 27
Corporate 17 (144) 161 89 (30) 119
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Total 36 (111) 147 193 (54) 247
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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 $11 million quarter over
quarter and $26 million year to date compared to the same period in 2009,
reflecting the impact of the participation by shareholders in the Corporation's
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 offering of five-year fixed
rate reset First Preference Shares, Series H. 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 $48 million for the third quarter, up $3 million
from the same quarter in 2009, due mainly to an increase in the quarterly common
share dividend. Common share dividends were $193 million year to date, up $60
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. The dividend
declared per common share in each of the first, second and third quarters of
2010 was $0.28, while the dividend declared per common share in each of the
first, second and third quarters of 2009 was $0.26.
Preference share dividends increased $2 million quarter over quarter and $7
million year to date compared to the same period in 2009, as a result of the
dividends associated with the 10 million First Preference Shares, Series H that
were issued in January 2010.
Contractual Obligations: Consolidated contractual obligations of Fortis with
external third parties over the next five years and for periods thereafter, as
of September 30, 2010, are outlined in the following table. A detailed
description of the nature of the obligations is provided below and in the MD&A
for the year ended December 31, 2009.
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Contractual Obligations
(Unaudited) As at Due in Due in
September 30, 2010 ($ Due within years 2 years 4 Due after
millions) Total 1 year and 3 and 5 5 years
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Long-term debt 5,534 155 594 839 3,946
Brilliant Terminal
Station 60 3 5 5 47
Gas purchase contract
obligations (1) 660 394 189 77 -
Power purchase
obligations
FortisBC (2) 2,932 43 90 81 2,718
FortisOntario 471 32 96 169 174
Maritime Electric 45 26 2 2 15
Belize Electricity 181 20 38 43 80
Capital cost 417 19 36 32 330
Joint-use asset and
shared service
agreements (3) 64 4 7 7 46
Office lease - FortisBC 18 1 3 3 11
Operating lease
obligations 138 17 30 27 64
Equipment purchase -
Fortis Turks and Caicos 3 3 - - -
Defined benefit pension
funding contributions
(4) 40 20 16 2 2
Other (5) 21 5 9 6 1
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Total 10,584 742 1,115 1,293 7,434
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(1)Based on index prices as at September 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)In September 2010, FortisAlberta and an Alberta transmission service
provider renewed shared-service agreements for an additional five years
for a total of approximately $4 million.
(4)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, 2010 Terasen (covering unionized employees)
and FortisBC
December 31, 2011 Newfoundland Power
The estimate of defined pension funding contributions above includes the
impact of the outcome of the December 31, 2009 actuarial valuation,
finalized during the third quarter of 2010, associated with the defined
benefit pension plan covering non-unionized employees at Terasen.
(5)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
September 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. Caribbean Utilities 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.
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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 utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
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Capital Structure
(Unaudited) As at
September 30, 2010 December 31, 2009
($ millions) (%) ($ millions) (%)
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Total debt and capital
lease obligations
(net of cash) (1) 5,811 58.2 5,830 60.2
Preference shares (2) 912 9.2 667 6.9
Common shareholders'
equity 3,255 32.6 3,193 32.9
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Total (3) 9,978 100.0 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
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The change in the capital structure was driven by the issuance of $250 million
preference shares in January 2010 and increased common shares outstanding,
reflecting the impact of the Corporation's Dividend Reinvestment and Share
Purchase Plan. Repayments of long-term debt and capital lease obligations
year-to-date 2010 were largely offset by an increase in committed credit
facility borrowings.
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 A(low) (unsecured debt credit rating)
In October 2010, DBRS upgraded the Corporation's unsecured debt credit rating to
A(low) from BBB(high). In May 2010, S&P confirmed its existing debt credit
rating for Fortis at A-(stable). These credit ratings, and the recent upgrade 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.
Year-to-date 2010, gross consolidated capital expenditures were $703 million. A
breakdown of gross consolidated capital expenditures by segment year-to-date
2010 is provided in the following table.
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Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-date September 30, 2010
($ millions)
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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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182 258 99 56 33 628 53 8 14 703
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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
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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, TGI's Fraser River South Bank South Arm Rehabilitation Project
experienced difficulties with one of the directional drills and the project is
now expected to be in service in 2011, rather than in 2010. The project is now
expected to cost approximately $36 million, increased from the $27 million
forecast as at December 31, 2009.
During 2010, FortisAlberta has continued with the replacement of conventional
customer meters with AMR technology. The capital cost of the AMR project is now
expected to be approximately $126 million (excluding $15 million for the pilot
program), a decrease from the $140 million (excluding the pilot program)
forecast as at December 31, 2009. In July 2010, the AUC limited the project cost
to $104 million, which was the original amount provided in the AUC-approved
2008/2009 NSA. As of the end of October 2010, approximately $106 million has
been incurred on this project. For further information, refer to the "Material
Regulatory Decisions and Applications" section of this MD&A.
In May 2010, Fortis Turks and Caicos received delivery of one of two
diesel-powered generating units that have a combined generating capacity of
approximately 18 MW. Commissioning of the first unit began in October 2010 and
the unit is expected to come into service in January 2011. The delivery of the
second unit is anticipated in January 2011.
In October 2010, the Corporation, in partnership with Columbia Power Corporation
and Columbia Basin Trust ("CPC/CBT"), concluded definitive agreements to
construct the Waneta Expansion, at an estimated cost of approximately $900
million. Construction is expected to start in November 2010. For additional
information, refer to the "Subsequent Events" section of this MD&A.
Over the five-year period 2011 through 2015, consolidated gross capital
expenditures are expected to approach $5.5 billion, including work on the Waneta
Expansion Project. Of the capital spending, approximately 63 per cent is
expected to be incurred at the Regulated Electric Utilities, driven by
FortisAlberta and FortisBC, 21 per cent is expected to be incurred at the
Regulated Gas Utilities and 16 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.
Over the next five years, as at September 30, 2010, management expects
consolidated long-term debt maturities and repayments to average approximately
$320 million annually. 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 $5
million (BZ$10 million) as at September 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 September 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 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 September 30, 2010 and are expected to remain compliant
throughout 2010.
Credit Facilities: As at September 30, 2010, the Corporation and its
subsidiaries had consolidated credit facilities of approximately $2.1 billion,
of which $1.2 billion was unused, including $386 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 $2.0 billion of the total credit facilities are committed
facilities, most of which have maturities between 2011 and 2013.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities (Unaudited) As at
Corporate Regulated Fortis September December
($ millions) and Other Utilities Properties 30, 2010 31, 2009
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Total credit
facilities 645 1,453 13 2,111 2,153
Credit facilities
utilized:
Short-term
borrowings - (340) (1) (341) (415)
Long-term debt
(including
current portion) (214) (244) - (458) (208)
Letters of credit
outstanding (1) (111) - (112) (100)
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Credit facilities
unused 430 758 12 1,200 1,430
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As at September 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, but there is an increase in pricing reflecting current general market
conditions.
In August 2010, Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility obtaining an extension to the maturity of
the facility to August 2013 from August 2011. The amended credit facility
agreement reflects an increase in pricing as a result of current general market
conditions but, otherwise, contains substantially similar terms and conditions
as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current
liabilities, other assets and other liabilities in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or nature of these instruments. The fair
value of long-term debt is calculated using quoted market prices when available.
When quoted market prices are not available, the fair value is determined by
discounting the future cash flows of the specific debt instrument at an
estimated yield to maturity equivalent to benchmark government bonds or treasury
bills, with similar terms to maturity, plus a market credit risk premium equal
to that of issuers of similar credit quality. Since the Corporation does not
intend to settle the long-term debt prior to maturity, the fair value estimate
does not represent an actual liability and, therefore, does not include exchange
or settlement costs. The fair value of the Corporation's preference shares is
determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt
and preference shares were as follows.
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Financial Instruments
(Unaudited) As at
September 30, 2010 December 31, 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Long-term debt, including
current portion (1) 5,534 6,407 5,502 5,906
Preference shares,
classified as debt (2) 320 350 320 348
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(1)Carrying value as at September 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 o f
a financial instrument; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was
$610 million as at September 30, 2010 (December 31, 2009 - carrying value
$347 million; fair value $356 million).
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Risk Management: The Corporation's earnings from, and net investment in,
self-sustaining foreign subsidiaries are exposed to fluctuations in the US
dollar-to-Canadian dollar exchange rate. The Corporation has effectively
decreased the above exposure through the use of US dollar borrowings at the
corporate level. The foreign exchange gain or loss on the translation of US
dollar-denominated interest expense partially offsets the foreign exchange loss
or gain on the translation of the Corporation's foreign subsidiaries' earnings,
which are denominated in US dollars or a currency pegged to the US dollar.
Belize Electricity's reporting currency is the Belizean dollar, while the
reporting currency of Caribbean Utilities, 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 September 30, 2010, all of the Corporation's corporately issued 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
September 30, 2010, the Corporation had approximately US$199 million (December
31, 2009 - US$174 million) in foreign net investments remaining to be hedged.
Foreign currency exchange rate fluctuations associated with the translation of
the Corporation's corporately held US dollar borrowings designated as hedges are
recorded in other comprehensive income and serve to help offset unrealized
foreign currency gains and losses on the foreign net investments, which are also
recorded in other comprehensive income.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes.
The following table summarizes the valuation of the Corporation's consolidated
derivative financial instruments.
Derivative Financial Instruments
(Unaudited) As at
September 30, 2010 December 31, 2009
Estimated Estimated
Term Fair Carrying Fair
to Number Carrying Value Value Value
Maturity of Value($ ($ ($ ($
Liability (years) Contracts millions) millions) millions) millions)
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Interest rate less than
swap 1 1 - - - -
Foreign
exchange
forward less than
contracts 1 to 2 2 - - - -
Natural gas
derivatives:
Swaps and
options Up to 4 206 (202) (202) (119) (119)
Gas purchase
contract
premiums Up to 3 87 (2) (2) (3) (3)
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The interest rate swap, which matured in October 2010, was held by Fortis
Properties and was designated as a hedge of the cash flow risk related to
floating-rate long-term debt and matured in October 2010. The effective portion
of changes in the value of the interest rate swap at Fortis Properties was
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$11 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$3 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. See the "Business Risk Management - Commodity Price Risk"
section of this MD&A for further information.
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 September 30, 2010 and as at December 31, 2009. The
fair values of the natural gas derivatives were recorded in accounts payable as
at September 30, 2010 and as at December 31, 2009.
The interest rate swap was 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 September 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 year-to-date 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 were
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 for further information on regulation.
Capital Project Budget Overruns and Financing Risk in the Corporation's
Non-Regulated Business: In its non-regulated business, Fortis generally bears
the risk for budget overruns on capital projects including increased costs
associated with higher financing expense, schedule delays and worse than
expected performance. In contrast, these budget overruns, when incurred
prudently in the regulated business, can be recovered in customer rates as part
of cost of service. Budgets for capital projects are established, in part, on
estimates which are subject to a number of assumptions including future economic
conditions; productivity; performance of employees, contractors, subcontractors
or equipment suppliers; price; availability of labour, equipment and materials
and other requirements that may affect project costs or the schedule, such as
obtaining the required environmental permits, licenses and approvals on a timely
basis. The risk of cost overruns is mitigated by contractual approach, regular
and proactive monitoring by employees with appropriate expertise and by regular
review by senior management. Cost overruns may also occur when unforeseen
circumstances arise. The cost of financing large capital projects is subject to
conditions experienced in the capital markets which may result in higher
financing costs than originally estimated. See the "Subsequent Events" section
of this MD&A for further information on the non-regulated Waneta Expansion
Project.
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
Terasen, TGI, TGVI, FortisAlberta and Newfoundland Power and upgraded FortisBC's
senior unsecured debt credit rating to Baa1 from Baa2. DBRS also upgraded
FortisBC's secured and unsecured debenture credit rating to A(low) from
BBB(high). The credit rating upgrades for FortisBC reflect progress made by the
Company in addressing issues previously identified as credit challenges. DBRS
has confirmed its existing debt credit ratings for Terasen and TGI and upgraded
the credit rating of the Corporation's unsecured debt to A(low) from at
BBB(high). 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+'.
Commodity Price Risk: On an annual basis, Terasen files a Price Risk Management
Plan which seeks approval for the Company's gas commodity hedging plan for the
next three years for TGI and the next five years for TGVI. During the third
quarter of 2010, the BCUC denied the application that was filed by Terasen
earlier in 2010 and directed the Company to undertake a review of the primary
objectives of the Price Risk Management Plan. Terasen plans to file its review
of the Price Risk Management Plan with the BCUC by the end of February 2011.
Terasen has completed its hedging program for the upcoming winter period related
to previously approved Price Risk Management Plans, but has not entered into any
additional derivatives for any subsequent periods.
Defined Benefit Pension Plan Performance and Funding Requirements: As at
September 30, 2010, the fair value of the Corporation's consolidated defined
benefit pension plan assets was $706 million, up $45 million, or 6.8 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 nine months ended September 30, 2010, amortization
of $1 million and $3 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 September 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 nine months ended September 30, 2010,
actual asset removal costs of approximately $8 million were incurred,
with approximately $6 million recorded in operating expenses and $2
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. 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 nine months
ended September 30, 2010, losses of approximately $6 million and $11
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.
iii.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 for the three and nine months ended
September 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.
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") had been delayed based on comments received
in response to the IASB's July 2009 Exposure Draft on Rate-Regulated Activities
and decisions by the IASB to conduct further research and analysis.
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 Rate-Regulated Activities
Project; however, no decision was made as to whether regulatory assets and
liabilities could be recognized under IFRS.
At its September 2010 meeting, the IASB continued its discussions on
rate-regulated activities. However, the IASB did not reach conclusions on any of
the associated technical issues discussed at the meeting. The IASB did reconfirm
its earlier view that the matter could not be resolved quickly and decided that
the next step should be to consider whether to include a project on accounting
for the effects of rate-regulated activities in its future agenda. The IASB
decided, therefore, to include on its future agenda, in consultation with the
public, a request for views on what form a future project might take, if any, to
address accounting for the effects of rate-regulated activities. The feedback to
be received is expected to assist the IASB in setting its future agenda.
Potential future steps on how to deal with accounting for the effects of
rate-regulated activities under IFRS include, but are not limited to: (i) a
disclosure only standard; (ii) an interim standard to grandfather previous
country-specific GAAP associated with accounting for the effects of
rate-regulated activities with some limited improvements; (iii) a medium-term
project focused specifically on accounting for the effects of rate-regulation;
and/or (iv) a comprehensive project on intangible assets that would include
accounting for the effects of rate-regulated activities.
On July 28, 2010, the Canadian Accounting Standards Board ("AcSB") issued an
Exposure Draft, Adoption of IFRSs by Entities with Rate-Regulated Activities,
(the "July 2010 ED") 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 July 2010 ED also proposed
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.
On September 7 and 8, 2010, the AcSB re-deliberated the proposals in its July
2010 ED. The AcSB decided that an optional deferral of the mandatory IFRS
changeover date for entities with rate-regulated activities was warranted, but
that the deferral should last for one year only. Part I of the CICA Handbook has
been updated to reflect the AcSB's decision. Adoption of IFRS by qualifying
entities with rate-regulated activities is now mandatory under Canadian GAAP for
interim and annual periods beginning on or after January 1, 2012.
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 one-year deferral option. The
Corporation has elected to defer the adoption of IFRS until January 1, 2012 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, 2011.
A Canadian publicly accountable entity that is also registered with the US
Securities and Exchange Commission ("SEC") (i.e., an "SEC Issuer") has the
option to use US Generally Accepted Accounting Principles ("US GAAP") for the
purposes of meeting its Canadian financial reporting and securities filing
requirements. Depending on the extent of progress with respect to the
application of IFRS to rate-regulated activities and the ability to recognize
regulatory assets and liabilities under IFRS, the Corporation may consider
whether US GAAP, as opposed to IFRS, would provide the most useful and relevant
presentation of its financial results. If determined to be in its best
interests, the Corporation may, therefore, seek to become an SEC Issuer and use
US GAAP as its basis of accounting for all interim and annual periods beginning
on or after January 1, 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 for the three and nine months ended
September 30, 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.
During the third quarter of 2010, FortisAlberta submitted a Compliance Filing,
related to its 2010 and 2011 DTA, which included forecast amortization expense
of $125 million and $142 million for 2010 and 2011, respectively. The forecast
amortization expense reflects an increase in the composite amortization rate to
4.27 per cent for 2010 from 3.94 per cent for 2009.
The increases in amortization at TGI, TGVI and FortisAlberta has been approved
for recovery in customer 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. The asset-retirement
obligation may change from period to period because of changes in the estimation
of these uncertainties. As at September 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 for 2010 and 2011, 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 third quarter and
approximately $3 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 had disputed 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 was recorded as a long-term
regulatory deferral asset. TGI was successful in its appeal to the British
Columbia Court of Appeal, which took place in May 2010. During the third quarter
of 2010, TGI received a refund of the majority of the balance with the amount
withheld relating to a separate reassessment.
In 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. During
the third quarter of 2010, final reassessments were received and Canada Revenue
Agency refunded the Company's $6 million deposit. As ordered by its regulator,
the $6 million refund has been applied to the outstanding balance associated
with the operation of the Energy Cost Adjustment Mechanism.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended December 31, 2008 through September 30, 2010. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements which, in the opinion of management, have been
prepared in accordance with Canadian GAAP and as required by utility regulators.
The timing of the recognition of certain assets, liabilities, revenue and
expenses, as a result of regulation, may differ from that otherwise expected
using Canadian GAAP for non-regulated entities. The differences and nature of
regulation are disclosed in Notes 2 and 4 to the Corporation's 2009 annual
audited consolidated financial statements. The quarterly financial results are
not necessarily indicative of results for any future period and should not be
relied upon to predict future performance.
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Summary of Quarterly Results (Unaudited)
Net Earnings
Attributable
to Common
Equity
Revenue ($ Shareholders Earnings per Common Share
Quarter Ended millions) ($ millions) Basic ($) Diluted ($)
--------------------------------------------------------------------------
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September 30, 2010 720 45 0.26 0.26
June 30, 2010 834 55 0.32 0.32
March 31, 2010 1,073 100 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
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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 for the fourth
quarter ended December 31, 2008 included two additional months of contribution
from Caribbean Utilities, resulting from a change in the utility's fiscal year
end. Financial results 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. The commissioning of the Vaca hydroelectric
generating facility in March 2010 has favourably impacted financial results
since this date. Revenue for the third quarter ended September 30, 2010
reflected the favourable cumulative retroactive impact associated with a
2010-2011 regulatory rate decision for FortisAlberta. 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.
September 2010/September 2009 - Net earnings attributable to common equity
shareholders were $45 million, or $0.26 per common share, for the third quarter
of 2010 compared to earnings of $36 million, or $0.21 per common share, for the
third quarter of 2009. The increase in earnings was mainly due to improved
performance at the regulated electric utilities in western Canada and
non-regulated hydroelectric generation operations, partially offset by a higher
loss incurred at the Terasen Gas companies and higher corporate expenses.
Improved performance at the regulated utilities in western Canada was due to
higher allowed ROEs and/or equity component, growth in electrical infrastructure
investment combined with an increase in the number of customers at
FortisAlberta, partially offset by a weather-related decrease in electricity
sales at FortisBC and lower net transmission revenue at FortisAlberta. The
increase in earnings' contribution from non-regulated hydroelectric generation
operations was the result of increased production in Belize, driven by higher
rainfall and the commissioning of the Vaca hydroelectric generating facility in
March 2010, and lower finance charges. The higher loss quarter over quarter at
the Terasen Gas companies largely related to increased operating and maintenance
expenses at TGI that were approved by the BCUC as part of the recent NSA. The
loss in the third quarter of 2010, however, was reduced by $4 million (after
tax) related to the BCUC-approved reversal of most of the project cost overrun
previously expensed in the fourth quarter of 2009 associated with the conversion
of Whistler customer appliances from propane to natural gas. The increase in
corporate expenses was associated with higher preference share dividends,
partially offset by lower finance charges.
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 an increase in 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 an increase in 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.
SUBSEQUENT EVENTS
In October 2010, the Corporation, in partnership with CPC/CBT, concluded
definitive agreements to construct the Waneta Expansion at an estimated cost of
approximately $900 million, and SNC-Lavalin was awarded a contract for
approximately $590 million to design and build the Waneta Expansion. The
facility is sited adjacent to the Waneta Dam and powerhouse facilities on the
Pend d'Oreille River, south of Trail, British Columbia and will have a
generating capacity of 335 MW. CBC/CBT are both 100 per cent owned corporations
of the Government of British Columbia. Fortis owns a 51 per cent interest in the
Waneta Expansion and will operate and maintain the non-regulated investment when
the facility comes into service, which is expected in spring 2015. Construction
is expected to start in November 2010. The Waneta Expansion will be included in
the Canal Plant Agreement and will receive fixed energy and capacity
entitlements based upon long-term average water flows, thereby significantly
reducing hydrologic risk associated with the project. The energy, approximately
630 GWh, (and associated capacity required to deliver such energy) for the
Waneta Expansion will be sold to BC Hydro under a long-term energy purchase
agreement. The surplus capacity, equal to 234 MW on an average annual basis,
will be sold to FortisBC under a long-term capacity purchase agreement, which
was accepted by the BCUC in September 2010.
In October 2010, FortisAlberta issued 40-year $125 million 4.80% unsecured
debentures, the net proceeds of which will be used to repay committed credit
facility borrowings that were incurred primarily to finance capital
expenditures, and for general corporate purposes.
In October 2010, Fortis redeemed its maturing $100 million 7.40% senior
unsecured debentures with proceeds from borrowings under the Corporation's
committed credit facility.
OUTLOOK
The Corporation's significant capital program, which is expected to be
approximately $1.1 billion in 2010 and approach $5.5 billion over the five-year
period from 2011 through 2015, including work on the Waneta Expansion Project,
should drive growth in earnings and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing
on regulated electric and natural gas utilities in the United States and Canada.
Fortis will also pursue growth in its non-regulated businesses in support of its
regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at November 4, 2010, the Corporation had issued and outstanding 173.7 million
common shares; 5.0 million First Preference Shares, Series C; 8.0 million First
Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 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 November 4, 2010 is as follows:
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Number of
Potential Conversion of Securities into Common Shares Common Shares
(Unaudited) As at November 4, 2010(Security) (millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Stock Options 4.9
Convertible Debt 1.4
First Preference Shares, Series C 3.9
First Preference Shares, Series E 6.4
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Total 16.6
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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 nine months ended September 30, 2010 and 2009
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30, December 31,
2010 2009
--------------------------------------------------------------------------
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(Notes 2 & 22)
ASSETS
Current assets
Cash and cash equivalents $64 $85
Accounts receivable 443 595
Prepaid expenses 33 16
Regulatory assets (Note 5) 299 223
Inventories (Note 6) 202 178
Future income taxes 12 29
--------------------------------
1,053 1,126
Other assets 170 174
Regulatory assets (Note 5) 829 747
Future income taxes 22 17
Utility capital assets 8,047 7,697
Income producing properties 560 559
Intangible assets 270 282
Goodwill 1,557 1,560
--------------------------------
$12,508 $12,162
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 19) $341 $415
Accounts payable and accrued charges 826 852
Dividends payable 52 3
Income taxes payable 15 23
Regulatory liabilities (Note 5) 45 53
Current installments of long-term debt and
capital lease obligations (Note 7) 158 224
Future income taxes 6 24
--------------------------------
1,443 1,594
Other liabilities 310 295
Regulatory liabilities (Note 5) 475 444
Future income taxes 615 570
Long-term debt and capital lease
obligations (Note 7) 5,376 5,276
Preference shares 320 320
--------------------------------
8,539 8,499
--------------------------------
Shareholders' equity
Common shares (Note 8) 2,555 2,497
Preference shares (Note 9) 592 347
Contributed surplus 13 11
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (Note
11) (88) (83)
Retained earnings 770 763
--------------------------------
3,847 3,540
Non-controlling interests 122 123
--------------------------------
3,969 3,663
--------------------------------
$12,508 $12,162
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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 September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2010 2009 2010 2009
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(Note 2) (Note 2)
Revenue $720 $665 $2,627 $2,623
--------------------------------------------
Expenses
Energy supply costs 259 253 1,178 1,279
Operating 196 183 600 565
Amortization 117 91 307 274
--------------------------------------------
572 527 2,085 2,118
--------------------------------------------
Operating income 148 138 542 505
Finance charges (Note 13) 88 91 266 267
--------------------------------------------
Earnings before corporate
taxes 60 47 276 238
Corporate taxes (Note 14) 5 2 48 34
--------------------------------------------
Net earnings $55 $45 $228 $204
--------------------------------------------
Net earnings attributable to:
Non-controlling interests $3 $4 $7 $9
Preference equity shareholders 7 5 21 14
Common equity shareholders 45 36 200 181
--------------------------------------------
$55 $45 $228 $204
--------------------------------------------
Earnings per common share
(Note 8)
Basic $0.26 $0.21 $1.16 $1.06
Diluted $0.26 $0.21 $1.15 $1.05
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2010 2009 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Note 2) (Note 2)
Balance at beginning of period $773 $691 $763 $634
Net earnings attributable to
common and preference equity
shareholders 52 41 221 195
-------------------------------------------
825 732 984 829
Dividends on common shares (48) (45) (193) (133)
Dividends on preference shares
classified as equity (7) (5) (21) (14)
-------------------------------------------
Balance at end of period $770 $682 $770 $682
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(Note 2) (Note 2)
Net earnings $55 $45 $228 $204
----------------------------------------
Other comprehensive (loss) income
Unrealized foreign currency
translation losses on net
investments in self-sustaining
foreign operations (21) (51) (13) (79)
Gains on hedges of net investments
in self-sustaining foreign
operations 13 37 8 59
Corporate tax expense (2) (5) (1) (8)
----------------------------------------
Unrealized foreign currency
translation losses, net of
hedging activities and tax (Note
11) (10) (19) (6) (28)
----------------------------------------
Gain on derivative instruments
designated as cash flow hedges,
net of tax (Note 11) - - - 1
----------------------------------------
Reclassification to earnings of
net losses on derivative
instruments previously
discontinued as cash flow hedges,
net of tax (Note 11) 1 - 1 -
----------------------------------------
Comprehensive income $46 $26 $223 $177
----------------------------------------
Comprehensive income attributable
to:
Non-controlling interests $3 $4 $7 $9
Preference equity shareholders 7 5 21 14
Common equity shareholders 36 17 195 154
----------------------------------------
$46 $26 $223 $177
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(Note 2) (Note 2)
Operating activities
Net earnings $55 $45 $228 $204
Items not affecting cash:
Amortization - utility capital
assets and income producing
properties 107 78 276 238
Amortization - intangible assets 10 12 30 32
Amortization - other - 1 1 4
Future income taxes - 2 (1) 9
Other (3) (2) (1) (9)
Change in long-term regulatory
assets and liabilities (4) 7 (4) 30
----------------------------------------
165 143 529 508
Change in non-cash operating
working capital (36) (80) 53 59
----------------------------------------
129 63 582 567
----------------------------------------
Investing activities
Change in other assets and other
liabilities (2) 1 1 (4)
Capital expenditures - utility
capital assets (256) (251) (672) (725)
Capital expenditures - income
producing properties (5) (4) (14) (15)
Capital expenditures - intangible
assets (7) (12) (17) (23)
Contributions in aid of
construction 17 14 41 40
Proceeds on sale of utility
capital assets - 1 3 1
Business acquisition - - - (7)
----------------------------------------
(253) (251) (658) (733)
----------------------------------------
Financing activities
Change in short-term borrowings 122 168 (4) (71)
Proceeds from long-term debt, net
of issue costs - 209 - 610
Repayments of long-term debt and
capital lease obligations (3) (57) (215) (148)
Net borrowings (repayments) under
committed credit facilities 36 (111) 193 (54)
Advances (to) from non-
controlling interests - (5) 1 (5)
Issue of common shares, net of
costs 19 8 58 32
Issue of preference shares, net
of costs - - 242 -
Dividends
Common shares (48) (45) (193) (133)
Preference shares (7) (5) (21) (14)
Subsidiary dividends paid to
non-controlling interests (2) (3) (6) (8)
----------------------------------------
117 159 55 209
----------------------------------------
Effect of exchange rate changes on
cash and cash equivalents - (2) - (3)
----------------------------------------
Change in cash and cash
equivalents (7) (31) (21) 40
Cash and cash equivalents,
beginning of period 71 137 85 66
--------------------------------------------------------------------------
Cash and cash equivalents, end of
period $64 $106 $64 $106
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 nine months ended September 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 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 nine months ended September 30, 2010, amortization
of $1 million and $3 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 September 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 nine months ended September 30, 2010,
actual asset removal costs of approximately $8 million were incurred,
with approximately $6 million recorded in operating expenses and $2
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. 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 nine months
ended September 30, 2010, losses of approximately $6 million and $11
million, respectively, were deferred and recorded as a regulatory asset
on the consolidated balance sheet (Note 5). 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.
iii.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 nine
months ended September 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, would 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 had been delayed
based on comments received in response to the Exposure Draft and decisions by
the IASB to conduct further research and analysis.
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 Rate-Regulated Activities
Project; however, no decision was made as to whether regulatory assets and
liabilities could be recognized under IFRS.
At its September 2010 meeting, the IASB continued its discussions on
rate-regulated activities. However, the IASB did not reach conclusions on any of
the associated technical issues discussed at the meeting.
The IASB did reconfirm its earlier view that the matter could not be resolved
quickly and decided that the next step should be to consider whether to include
a project on accounting for the effects of rate-regulated activities in its
future agenda. The IASB decided, therefore, to include on its future agenda, in
consultation with the public, a request for views on what form a future project
might take, if any, to address accounting for the effects of rate-regulated
activities. The feedback to be received is expected to assist the IASB in
setting its future agenda. Potential future steps on how to deal with accounting
for the effects of rate-regulated activities under IFRS include, but are not
limited to: (i) a disclosure only standard; (ii) an interim standard to
grandfather previous country-specific GAAP associated with accounting for the
effects of rate-regulated activities with some limited improvements; (iii) a
medium-term project focused specifically on accounting for the effects of
rate-regulation; and/or (iv) a comprehensive project on intangible assets that
would include accounting for the effects of rate-regulated activities.
On July 28, 2010, the AcSB issued an Exposure Draft, Adoption of IFRSs by
Entities with Rate-Regulated Activities, (the "July 2010 ED") 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 July 2010 ED also proposed 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.
On September 7 and 8, 2010, the AcSB re-deliberated the proposals in its July
2010 ED. The AcSB decided that an optional deferral of the mandatory IFRS
changeover date for entities with rate-regulated activities was warranted, but
that the deferral should last for one year only. Part I of the CICA Handbook has
been updated to reflect the AcSB's decision. Adoption of IFRS by qualifying
entities with rate-regulated activities is now mandatory under Canadian GAAP for
interim and annual periods beginning on or after January 1, 2012.
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 one-year deferral option. The
Corporation has elected to defer the adoption of IFRS until January 1, 2012 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, 2011.
A Canadian publicly accountable entity that is also registered with the US
Securities and Exchange Commission ("SEC") (i.e., an "SEC Issuer") has the
option to use US Generally Accepted Accounting Principles ("US GAAP") for the
purposes of meeting its Canadian financial reporting and securities filing
requirements. Depending on the extent of progress with respect to the
application of IFRS to rate-regulated activities and the ability to recognize
regulatory assets and liabilities under IFRS, the Corporation may consider
whether US GAAP, as opposed to IFRS, would provide the most useful and relevant
presentation of its financial results. If determined to be in its best
interests, the Corporation may, therefore, seek to become an SEC Issuer and use
US GAAP as its basis of accounting for all interim and annual periods beginning
on or after January 1, 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 nine months ended
September 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.
During the third quarter of 2010, FortisAlberta submitted a Compliance Filing,
related to its 2010 and 2011 Distribution Tariff Application, which included
forecast amortization expense of $125 million and $142 million for 2010 and
2011, respectively. The forecast amortization expense reflects an increase in
the composite amortization rate to 4.27 per cent for 2010 from 3.94 per cent for
2009.
The increase in amortization at TGI, TGVI and FortisAlberta has been approved
for recovery in customer 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. The asset-retirement
obligation may change from period to period because of changes in the estimation
of these uncertainties. As at September 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 third quarter and
approximately $3 million year to date over the same periods in 2009, with
corresponding decreases in utility capital assets. The resulting increase in
operating expenses has been approved for recovery in current customer delivery
rates.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A detailed description of the nature of the Corporation's regulatory
assets and liabilities is provided in Note 4 to the Corporation's 2009 annual
audited consolidated financial statements.
($ millions) As at
September 30, December 31,
2010 2009
--------------------------------------------------------------------------
(Note 22)
Regulatory Assets
Future income taxes 584 545
Rate stabilization accounts - Terasen Gas
companies 189 82
Rate stabilization accounts - electric
utilities 50 68
Regulatory other post-employment benefit
("OPEB") plan asset asasset 64 59
Alberta Electric System Operator ("AESO")
charges deferral 49 80
Point Lepreau (1) replacement energy
deferral 41 23
Accrued 2010 customer rate revenue at
FortisAlberta 27 -
Income taxes recoverable on OPEB plans 18 18
Energy management costs 18 14
Deferred development costs for capital (2) 12 7
Deferred losses on disposal of utility
capital assets (Note 2(ii)) 11 -
Deferred operating costs - FortisAlberta 8 -
Deferred costs - smart meters -
FortisOntario 7 4
Lease costs 6 6
Deferred pension costs 5 6
Southern Crossing Pipeline tax
reassessment (Note 20) 1 7
Other regulatory assets 38 51
--------------------------------------------------------------------------
Total Regulatory Assets 1,128 970
Less: Current Portion (299) (223)
--------------------------------------------------------------------------
Long-Term Regulatory Assets 829 747
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)New Brunswick Power Point Lepreau Nuclear Generating Station
(2)During the third quarter of 2010, approximately $5 million ($4 million
after tax) was deferred as a regulatory asset associated with the
regulator-approved reversal of most of the project cost overrun
previously expensed by TGWI in the fourth quarter of 2009 associated
with the conversion of Whistler customer appliances from propane to
natural gas.
($ millions) As at
September 30, December 31,
2010 2009
--------------------------------------------------------------------------
(Note 22)
Regulatory Liabilities
Future asset removal and site restoration
provision 338 326
Future income taxes 34 35
Rate stabilization accounts - Terasen Gas
companies 48 44
Rate stabilization accounts - electric
utilities 35 21
Performance-based rate-setting incentive
liabilities 9 15
Unrecognized net gains on disposal of
utility capital assets (1) 8 8
Unbilled revenue liability 7 10
Southern Crossing Pipeline deferral 7 9
Deferred interest 7 7
Other regulatory liabilities 27 22
--------------------------------------------------------------------------
Total Regulatory Liabilities 520 497
Less: Current Portion (45) (53)
--------------------------------------------------------------------------
Long-Term Regulatory Liabilities 475 444
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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
(ii))
6. INVENTORIES
($ millions) As at
September 30, December 31,
2010 2009
--------------------------------------------------------------------------
Gas in storage 182 159
Materials and supplies 20 19
--------------------------------------------------------------------------
202 178
--------------------------------------------------------------------------
--------------------------------------------------------------------------
During the three and nine months ended September 30, 2010, inventories of $90
million and $586 million, respectively, were expensed and reported in energy
supply costs in the interim consolidated statement of earnings ($98 million and
$722 million for the three and nine months ended September 30, 2009,
respectively). Inventories expensed to operating expenses were $3 million and
$10 million for the three and nine months ended September 30, 2010, respectively
($3 million and $10 million for the three and nine months ended September 30,
2009, respectively). Included in inventories expensed to operating expenses was
food and beverage costs at Fortis Properties of $2 million and $7 million for
the three and nine months ended September 30, 2010, respectively ($2 million and
$6 million for the three and nine months ended September 30, 2009,
respectively).
7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
($ millions) As at
September 30, December 31,
2010 2009
--------------------------------------------------------------------------
Long-term debt and capital lease
obligations 5,114 5,331
Long-term classification of committed
credit facilities (Note 19) 458 208
Deferred debt financing costs (38) (39)
--------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,534 5,500
Less: Current installments of long-term
debt and capital lease obligations (158) (224)
--------------------------------------------------------------------------
5,376 5,276
--------------------------------------------------------------------------
--------------------------------------------------------------------------
In April 2010, Terasen redeemed in full for cash its $125 million 8.0% Capital
Securities with proceeds from borrowings under the Corporation's committed
credit facility.
8. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value
Issued and
Outstanding As at
September 30, 2010 December 31, 2009
Number of Number of
Shares (in Amount ($ Shares (in Amount ($
thousands) millions) thousands) millions)
--------------------------------------------------------------------------
Common shares 173,579 2,555 171,256 2,497
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
September 30, 2010 September 30, 2010
Number of Number of
Shares (in Amount ($ Shares (in Amount ($
thousands) millions) thousands) millions)
--------------------------------------------------------------------------
Balance, beginning
of period 172,865 2,537 171,256 2,497
Consumer Share
Purchase Plan 11 - 39 1
Dividend
Reinvestment
Plan 534 15 1,605 43
Employee Share
Purchase Plan - - 193 5
Stock Option
Plans 169 3 486 9
--------------------------------------------------------------------------
Balance, end of
period 173,579 2,555 173,579 2,555
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Effective June 1, 2010, the Employee Share Purchase Plan ("ESPP") was amended as
approved by the Corporation's Board of Directors, such that future shares
purchased under the ESPP will be on the open market. The first investment date
under this amended ESPP was September 1, 2010.
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 September 30
2010 2009
------------------------------------------------------------
Weighted Earnings Weighted Earnings
Average per Average per
Earnings Shares Common Earnings Shares Common
($ (in ($ (in
millions) millions) Share millions) millions) Share
--------------------------------------------------------------------------
Basic Earnings
per Common
Share 45 173.2 $0.26 36 170.4 $0.21
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
--------------------------------------------------------------------------
50 187.4 41 186.4
Deduct anti-
dilutive
impacts:
Preference
shares (4) (11.9) (4) (13.9)
Convertible
debentures (1) (1.4) (1) (1.4)
--------------------------------------------------------------------------
Diluted
Earnings per
Common Share 45 174.1 $0.26 36 171.1 $0.21
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date September 30
2010 2009
------------------------------------------------------------
Weighted Earnings Weighted Earnings
Average per Average per
Earnings Shares Common Earnings Shares Common
($ (in ($ (in
millions) millions) Share millions) millions) Share
--------------------------------------------------------------------------
Basic Earnings
per Common
Share 200 172.4 $1.16 181 170.0 $1.06
Effect of
potential
dilutive
securities:
Stock options - 0.9 - 0.7
Preference
shares (Note
13) 12 11.9 12 13.9
Convertible
debentures 2 1.4 2 1.4
--------------------------------------------------------------------------
214 186.6 195 186.0
Deduct anti-
dilutive
impacts:
Convertible
debentures - - (2) (1.4)
--------------------------------------------------------------------------
Diluted
Earnings per
Common Share 214 186.6 $1.15 193 184.6 $1.05
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 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.
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 $4.41 per option.
The fair value was estimated on the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.66
Expected volatility (%) 25.1
Risk-free interest rate (%) 2.54
Weighted average expected life (years) 4.5
As at September 30, 2010, 5.0 million stock options were outstanding and 2.8
million stock options were vested.
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, gains and losses on
cash flow hedging activities and gains and losses on discontinued cash flow
hedging activities as described in Note 2 to the Corporation's 2009 annual
audited consolidated financial statements.
Quarter Ended September 30
2010 2009
-------------------------------------------------------
Ending Ending
Opening balance Opening balance
balance Net September balance Net September
($ millions) July 1 change 30 July 1 change 30
--------------------------------------------------------------------------
Unrealized foreign
currency
translation
losses, net of
hedging activities
and tax (74) (10) (84) (55) (19) (74)
Net (losses) gains
on derivative
instruments
previously
discontinued as
cash flow hedges,
net of tax (5) 1 (4) (5) - (5)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (79) (9) (88) (60) (19) (79)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date September 30
2010 2009
-------------------------------------------------------
Opening Ending Opening Ending
balance balance balance balance
January Net September January Net September
($ millions) 1 change 30 1 change 30
--------------------------------------------------------------------------
Unrealized foreign
currency
translation
losses, net of
hedging activities
and tax (78) (6) (84) (46) (28) (74)
(Losses) gains on
derivative
instruments
designated as cash
flow hedges, net
of tax - - - (1) 1 -
Net (losses) gains
on derivative
instruments
previously
discontinued as
cash flow hedges,
net of tax (5) 1 (4) (5) - (5)
--------------------------------------------------------------------------
Accumulated Other
Comprehensive Loss (83) (5) (88) (52) (27) (79)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 September 30, 2010 ($7 million for the quarter ended September 30,
2009) and $30 million year-to-date September 30, 2010 ($20 million year-to-date
September 30, 2009). The cost of providing the defined contribution arrangements
and group RRSPs for the quarter ended September 30, 2010 was $3 million ($3
million for the quarter ended September 30, 2009) and $10 million year-to-date
September 30, 2010 ($9 million year-to-date September 30, 2009).
13. FINANCE CHARGES
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2010 2009 2010 2009
--------------------------------------------------------------------------
Interest - Long-term debt
and capital lease
obligations 89 89 265 259
- Short-term
borrowings and
other 3 3 6 9
Interest charged to
construction (8) (5) (17) (13)
Dividends on
preference shares
classified as debt
(Note 8) 4 4 12 12
--------------------------------------------------------------------------
88 91 266 267
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 Year-to-Date
September 30 September 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 20 16 89 79
Preference share dividends 1 1 4 4
Difference between Canadian statutory
rate and rates applicable to foreign
subsidiaries (5) (5) (12) (12)
Difference in Canadian provincial
statutory rates applicable to
subsidiaries in different Canadian
jurisdictions (2) (1) (8) (5)
Items capitalized for accounting but
expensed for income tax purposes (9) (7) (29) (27)
Other - (2) 4 (5)
--------------------------------------------------------------------------
Corporate taxes 5 2 48 34
--------------------------------------------------------------------------
Effective tax rate 8.3% 4.3% 17.4% 14.3%
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at September 30, 2010, the Corporation had approximately $116 million
(December 31, 2009 - $122 million) in non-capital and capital loss
carryforwards, of which $16 million (December 31, 2009 - $16 million) has not
been recognized in the consolidated financial statements. The non-capital loss
carryforwards expire between 2010 and 2030.
15. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
----------------------------------------------------
Gas
Uti-
lities Electric Utilities
----------------------------------------------------
Tera-
Quarter Ended senGas Total
Compa- Elec- Elec-
September 30, 2010 nies - Fortis Fortis NF Other tric tric
Cana-
Cana- Alber- dian Cana- Carib-
($ millions) dian ta BC Power (1) dian bean
--------------------------------------------------------------------------
Revenue 206 109 62 99 87 357 92
Energy supply costs 90 - 16 50 57 123 57
Operating expenses 66 33 17 16 11 77 12
Amortization 27 45 10 12 7 74 9
--------------------------------------------------------------------------
Operating income 23 31 19 21 12 83 14
Finance charges 28 12 7 9 5 33 4
Corporate tax expense
(recovery) - - 1 4 2 7 (1)
--------------------------------------------------------------------------
Net (loss) earnings (5) 19 11 8 5 43 11
Non-controlling
interests - - - - - - 3
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net (loss) earnings
attributable to
common equity
shareholders (5) 19 11 8 5 43 8
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable assets 4,168 2,069 1,220 1,182 632 5,103 808
--------------------------------------------------------------------------
Total assets 5,076 2,296 1,441 1,182 695 5,614 946
--------------------------------------------------------------------------
Gross capital
expenditures (3) 72 102 36 20 12 170 17
--------------------------------------------------------------------------
Quarter Ended
September 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 208 84 57 93 70 304 90
Energy supply costs 98 - 15 50 46 111 52
Operating expenses 60 33 16 12 8 69 14
Amortization 25 25 9 11 5 50 9
--------------------------------------------------------------------------
Operating income 25 26 17 20 11 74 15
Finance charges 30 12 8 9 4 33 4
Corporate tax expense
(recovery) (2) (1) - 4 2 5 -
--------------------------------------------------------------------------
Net (loss) earnings (3) 15 9 7 5 36 11
Non-controlling
interests - - - - - - 4
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net (loss) earnings
attributable to
common equity
shareholders (3) 15 9 7 5 36 7
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 144
Identifiable assets 3,840 1,814 1,122 1,156 534 4,626 803
--------------------------------------------------------------------------
Total assets 4,748 2,041 1,343 1,156 597 5,137 947
--------------------------------------------------------------------------
Gross capital
expenditures (3) 62 109 30 20 10 169 27
--------------------------------------------------------------------------
NON-REGULATED
-------------------------
Quarter Ended Inter-
Corpo- seg-
September 30, 2010 Fortis Fortis rate ment
Gene-
ration Proper- and elimi- Conso-
($ millions) (2) ties Other nations lidated
-----------------------------------------------------------------
Revenue 13 60 8 (16) 720
Energy supply costs - - - (11) 259
Operating expenses 2 38 3 (2) 196
Amortization 1 5 1 - 117
-----------------------------------------------------------------
Operating income 10 17 4 (3) 148
Finance charges - 6 20 (3) 88
Corporate tax expense
(recovery) 1 2 (4) - 5
-----------------------------------------------------------------
Net (loss) earnings 9 9 (12) - 55
Non-controlling
interests - - - - 3
Preference share
dividends - - 7 - 7
-----------------------------------------------------------------
Net (loss) earnings
attributable to
common equity
shareholders 9 9 (19) - 45
-----------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable assets 193 580 108 (9) 10,951
-----------------------------------------------------------------
Total assets 193 580 108 (9) 12,508
-----------------------------------------------------------------
Gross capital
expenditures (3) 4 5 - - 268
-----------------------------------------------------------------
Quarter Ended
September 30, 2009
($ millions)
-----------------------------------------------------------------
Revenue 8 60 8 (13) 665
Energy supply costs - - - (8) 253
Operating expenses 2 37 2 (1) 183
Amortization 1 4 2 - 91
-----------------------------------------------------------------
Operating income 5 19 4 (4) 138
Finance charges 1 6 21 (4) 91
Corporate tax expense
(recovery) - 4 (5) - 2
-----------------------------------------------------------------
Net (loss) earnings 4 9 (12) - 45
Non-controlling
interests - - - - 4
Preference share
dividends - - 5 - 5
-----------------------------------------------------------------
Net (loss) earnings
attributable to
common equity
shareholders 4 9 (17) - 36
-----------------------------------------------------------------
Goodwill - - - - 1,563
Identifiable assets 187 574 149 (15) 10,164
-----------------------------------------------------------------
Total assets 187 574 149 (15) 11,727
-----------------------------------------------------------------
Gross capital
expenditures (3) 2 6 1 - 267
-----------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2)Results reflect contribution from the Vaca hydroelectric generating
facility in Belize which was commissioned in March 2010.
(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 statements of cash
flows
REGULATED
--------------------------------------------------
Gas
Uti-
lities Electric Utilities
--------------------------------------------------
Tera-
Year-to-Date senGas Total
Compa- Elec- Elec-
September 30, 2010 nies - Fortis Fortis NF Other tric tric
Cana-
Cana- Alber- dian Cana- Carib-
($ millions) dian ta BC Power (1) dian bean
--------------------------------------------------------------------------
Revenue 1,067 289 193 403 244 1,129 251
Energy supply costs 586 - 50 256 156 462 149
Operating expenses 201 104 53 47 33 237 35
Amortization 81 94 31 35 18 178 27
--------------------------------------------------------------------------
Operating income 199 91 59 65 37 252 40
Finance charges 84 40 23 27 16 106 13
Corporate tax expense
(recovery) 30 - 3 12 7 22 1
--------------------------------------------------------------------------
Net earnings (loss) 85 51 33 26 14 124 26
Non-controlling
interests - - - - - - 7
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings (loss)
attributable to common
equity shareholders 85 51 33 26 14 124 19
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable assets 4,168 2,069 1,220 1,182 632 5,103 808
--------------------------------------------------------------------------
Total assets 5,076 2,296 1,441 1,182 695 5,614 946
--------------------------------------------------------------------------
Gross capital
expenditures (3) 182 258 99 56 33 446 53
--------------------------------------------------------------------------
Year-to-Date
September 30, 2009
($ millions)
--------------------------------------------------------------------------
Revenue 1,166 245 184 381 205 1,015 255
Energy supply costs 722 - 50 246 133 429 142
Operating expenses 189 98 51 39 25 213 42
Amortization 76 70 28 34 14 146 30
--------------------------------------------------------------------------
Operating income 179 77 55 62 33 227 41
Finance charges 91 36 23 26 13 98 12
Corporate tax expense
(recovery) 19 (4) 3 12 7 18 1
--------------------------------------------------------------------------
Net earnings (loss) 69 45 29 24 13 111 28
Non-controlling
interests - - - - - - 8
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings (loss)
attributable to common
equity shareholders 69 45 29 24 13 111 20
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 144
Identifiable assets 3,840 1,814 1,122 1,156 534 4,626 803
--------------------------------------------------------------------------
Total assets 4,748 2,041 1,343 1,156 597 5,137 947
--------------------------------------------------------------------------
Gross capital
expenditures (3) 176 315 79 52 33 479 77
--------------------------------------------------------------------------
NON-REGULATED
-------------------------
Year-to-Date Inter-
Corpo- seg-
September 30, 2010 Fortis Fortis rate ment
Gene-
ration
(2) Proper- and elimi- Conso-
($ millions) ties Other nations lidated
-----------------------------------------------------------------
Revenue 26 169 23 (38) 2,627
Energy supply costs 1 - - (20) 1,178
Operating expenses 6 113 13 (5) 600
Amortization 3 13 5 - 307
-----------------------------------------------------------------
Operating income 16 43 5 (13) 542
Finance charges - 18 58 (13) 266
Corporate tax expense
(recovery) 2 6 (13) - 48
-----------------------------------------------------------------
Net earnings (loss) 14 19 (40) - 228
Non-controlling
interests - - - - 7
Preference share
dividends - - 21 - 21
-----------------------------------------------------------------
Net earnings (loss)
attributable to common
equity shareholders 14 19 (61) - 200
-----------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable assets 193 580 108 (9) 10,951
-----------------------------------------------------------------
Total assets 193 580 108 (9) 12,508
-----------------------------------------------------------------
Gross capital
expenditures (3) 7 14 1 - 703
-----------------------------------------------------------------
Year-to-Date
September 30, 2009
($ millions)
-----------------------------------------------------------------
Revenue 34 165 21 (33) 2,623
Energy supply costs 2 - - (16) 1,279
Operating expenses 8 109 9 (5) 565
Amortization 4 12 6 - 274
-----------------------------------------------------------------
Operating income 20 44 6 (12) 505
Finance charges 3 17 58 (12) 267
Corporate tax expense
(recovery) 2 8 (14) - 34
-----------------------------------------------------------------
Net earnings (loss) 15 19 (38) - 204
Non-controlling
interests 1 - - - 9
Preference share
dividends - - 14 - 14
-----------------------------------------------------------------
Net earnings (loss)
attributable to common
equity shareholders 14 19 (52) - 181
-----------------------------------------------------------------
Goodwill - - - - 1,563
Identifiable assets 187 574 149 (15) 10,164
-----------------------------------------------------------------
Total assets 187 574 149 (15) 11,727
-----------------------------------------------------------------
Gross capital
expenditures (3) 14 16 1 - 763
-----------------------------------------------------------------
(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. Results also reflect
contribution from the Vaca hydroelectric generating facility in Belize
which was commissioned in March 2010.
(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 statements 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 nine months ended
September 30, 2010 and 2009 were as follows.
Significant Inter-Segment Transactions
Quarter Ended September 30 Year-to-date September 30
($ millions) 2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Sales from Fortis
Generation to
Regulated Electric
Utilities - Caribbean 11 7 19 15
Sales from Fortis
Generation to Other
Canadian Electric
Utilities - - 1 1
Sales from
Newfoundland Power to
Fortis Properties 1 1 3 3
Inter-segment finance
charges on borrowings
from:
Corporate to
Regulated Electric
Utilities -
Canadian - - - 1
Corporate to
Regulated Electric
Utilities -
Caribbean - 1 2 2
Corporate to Fortis
Generation 1 1 3 3
Corporate to Fortis
Properties 2 2 8 6
--------------------------------------------------------------------------
--------------------------------------------------------------------------
16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter
Ended Year-to-date
September 30 September 30
($ millions) 2010 2009 2010 2009
--------------------------------------------------------------------------
Interest paid 90 88 284 272
Income taxes paid 9 2 46 82
--------------------------------------------------------------------------
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 utility's
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
As at
September 30, 2010 December 31, 2009
($ millions) (%) ($ millions) (%)
--------------------------------------------------------------------------
Total debt and capital
lease obligations
(net of cash) (1) 5,811 58.2 5,830 60.2
Preference shares (2) 912 9.2 667 6.9
Common shareholders'
equity 3,255 32.6 3,193 32.9
--------------------------------------------------------------------------
Total (3) 9,978 100.0 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 September 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 $5 million (BZ$10 million) as at September 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 September 30,
2010 (December 31, 2009 - $59 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan
are being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to expropriation matters.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 19.
18. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the nine months ended September 30, 2010 in the
designation of the Corporation's financial instruments from that disclosed in
the Corporation's 2009 annual audited consolidated financial statements. The
carrying values of financial instruments included in current assets, current
liabilities, other assets and other liabilities in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or the nature of these instruments. The
carrying and fair values of the Corporation's consolidated long-term debt and
preference shares were as follows:
As at
September 30, December 31,
2010 2009
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Long-term debt,
including current
portion (1) (2) 5,534 6,407 5,502 5,906
Preference shares,
classified as debt
(1) (3) 320 350 320 348
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Carrying value is measured at amortized cost using the effective
interest rate method.
(2)Carrying value as at September 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 $610
million as at September 30, 2010 (December 31, 2009 - carrying value $347
million; fair value $356 million).
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a market credit risk
premium equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt prior to maturity, the
fair value estimate does not represent an actual liability and, therefore, does
not include exchange or settlement costs. The fair value of the Corporation's
preference shares is determined using quoted market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes. The following table summarizes the valuation of the Corporation's
consolidated derivative financial instruments.
As at
September 30, 2010 December, 31, 2009
Estimated Estimated
Carrying Fair Carrying Fair
Term to Number Value Value Value Value
Maturity of ($ ($ ($ ($
Liability (years) Contracts millions) millions) millions) millions)
--------------------------------------------------------------------------
Interest
rate swap less than
(1) (2) 1 1 - - - -
Foreign
exchange
forward
contracts less than
(3) (4) 1 to 2 2 - - - -
Natural gas
derivatives
: (3) (5)
Swaps and
options Up to 4 206 (202) (202) (119) (119)
Gas
purchase
contract
premiums Up to 3 87 (2) (2) (3) (3)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Interest rate swap contract matured in October 2010.The contract had
the effect of fixing the rate of interest on the non-revolving credit
facilities of Fortis Properties at 5.32 per cent.
(2)The fair value measurements are Level 1, based on the three levels that
distinguish the level of pricing observability utilized in measuring
fair value.
(3)The fair value measurements are Level 2, based on the three levels that
distinguish the level of pricing observability utilized in measuring
fair value.
(4)The fair values of the foreign exchange forward contracts were recorded
in accounts receivable as at September 30, 2010 and as at December 31,
2009.
(5)The fair values of the natural gas derivatives were recorded in
accounts payable as at September 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 September 30, 2010, its gross credit risk exposure was approximately
$106 million, representing the projected value of retailer billings over a
60-day period. The Company has reduced its exposure to approximately $2 million
by obtaining from the retailers either a cash deposit, bond, letter of credit,
an investment-grade credit rating from a major rating agency or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The Terasen Gas companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments. 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
September 30, 2010 (June 30, 2010 - $17 million; March 31, 2010 - $17 million;
December 31, 2009 - $17 million; September 30, 2009 - $17 million), excluding
derivative financial instruments recorded in accounts receivable, was as
follows:
($ millions) As at
September June 30, March 31, December September
30, 2010 2010 2010 31, 2009 30, 2009
--------------------------------------------------------------------------
Not past due 399 442 518 527 305
Past due 0-30 days 29 49 63 52 32
Past due 31-60 days 9 14 14 8 9
Past due 61 days
and over 6 11 9 8 10
--------------------------------------------------------------------------
443 516 604 595 356
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at September 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 September 30, 2010, average
annual consolidated long-term debt maturities and repayments over the next five
years are expected to be approximately $320 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 September 30, 2010, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.2 billion was
unused. The credit facilities are syndicated almost entirely with the seven
largest Canadian banks, with no one bank holding more than 25 per cent of these
facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
($ millions) As at
Corporate Regulated Fortis September December
and Other Utilities Properties 30, 2010 31, 2009
--------------------------------------------------------------------------
Total credit
facilities 645 1,453 13 2,111 2,153
Credit facilities
utilized:
Short-term
borrowings - (340) (1) (341) (415)
Long-term debt
(including current
portion) (Note 7) (214) (244) - (458) (208)
Letters of credit
outstanding (1) (111) - (112) (100)
--------------------------------------------------------------------------
Credit facilities
unused 430 758 12 1,200 1,430
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at September 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, but there is an increase in pricing reflecting current general market
conditions.
In August 2010, Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility obtaining an extension to the maturity of
the facility to August 2013 from August 2011. The amended credit facility
agreement reflects an increase in pricing due to current general market
conditions but, otherwise, contains substantially similar terms and conditions
as the previous credit facility agreement.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates.
As at September 30, 2010, the Corporation's credit ratings were as follows:
Standard & Poor's A-(stable) (long-term corporate and unsecured debt
credit rating)
DBRS BBB(high) (unsecured debt credit rating)
In October 2010, DBRS upgraded the Corporation's unsecured debt credit rating to
A(low) from BBB(high).
The credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level and the significant
reduction in external debt at Terasen, the Corporation's strong credit metrics,
and the Corporation's demonstrated ability and continued focus of acquiring and
integrating stable regulated utility businesses financed on a conservative
basis.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at September 30, 2010.
Due in Due in
Financial Liabilities ($ Due within years 2 years 4 Due after
millions) 1 year and 3 and 5 5 years Total
--------------------------------------------------------------------------
Short-term borrowings 341 - - - 341
Trade and other accounts
payable 622 - - - 622
Natural gas derivatives
(1) 131 60 10 - 201
Foreign exchange forward
contracts (2) 9 5 - - 14
Dividends payable 52 - - - 52
Customer deposits (3) 1 2 1 2 6
Long-term debt, including
current portion (4) 155 594 839 3,946 5,534
Interest obligations on
long-term debt 329 639 589 4,502 6,059
Preference shares,
classified as debt - 123 - 197 320
Preference share dividend
obligations classified as
finance charges 17 33 19 10 79
--------------------------------------------------------------------------
1,657 1,456 1,458 8,657 13,228
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1)Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at September 30, 2010 at
$204 million.
(2)Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts receivable at fair value as at September 30, 2010
at less than $1 million.
(3)Customer deposits were recorded in other liabilities as at September
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 September 30, 2010, the Corporation's corporately issued 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 September
30, 2010, the Corporation had approximately US$199 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 September 30, 2010, Fortis Properties was party to one interest rate swap
agreement that effectively fixed the interest rate on variable-rate borrowings.
The interest rate swap agreement matured in October 2010.
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 had disputed 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 was recorded as a long-term
regulatory deferral asset (Note 5). TGI was successful in its appeal to the
British Columbia Court of Appeal, which took place in May 2010. During the third
quarter of 2010, TGI received a refund of the majority of the balance with the
amount withheld relating to a separate reassessment.
In 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. During
the third quarter of 2010, final reassessments were received and Canada Revenue
Agency refunded the Company's $6 million deposit. As ordered by its regulator,
the $6 million refund has been applied to the outstanding balance associated
with the operation of the Energy Cost Adjustment Mechanism.
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.
21. SUBSEQUENT EVENTS
In October 2010, the Corporation, in partnership with Columbia Power Corporation
and Columbia Basin Trust ("CPC/CBT"), concluded definitive agreements to
construct a 335-megawatt hydroelectric generating facility (the "Waneta
Expansion") at an estimated cost of approximately $900 million, and SNC-Lavalin
was awarded a contract for approximately $590 million to design and build the
Waneta Expansion. The facility is sited adjacent to the Waneta Dam and
powerhouse facilities on the Pend d'Oreille River, south of Trail, British
Columbia. CBC/CBT are both 100 per cent owned corporations of the Government of
British Columbia. Fortis owns a 51 per cent interest in the Waneta Expansion and
will operate and maintain the non-regulated investment when the facility comes
into service, which is expected in spring 2015. Construction is expected to
start in November 2010. The Waneta Expansion will be included in the Canal Plant
Agreement and will receive fixed energy and capacity entitlements based upon
long-term average water flows, thereby significantly reducing hydrologic risk
associated with the project. The energy, approximately 630 GWh, (and associated
capacity required to deliver such energy) for the Waneta Expansion will be sold
to BC Hydro under a long-term energy purchase agreement. The surplus capacity,
equal to 234 MW on an average annual basis, will be sold to FortisBC under a
long-term capacity purchase agreement, which was accepted by the BCUC in
September 2010.
In October 2010, FortisAlberta issued 40-year $125 million 4.80% unsecured
debentures, the net proceeds of which will be used to repay committed credit
facility borrowings that were incurred primarily to finance capital
expenditures, and for general corporate purposes.
In October 2010, Fortis redeemed its maturing $100 million 7.40% senior
unsecured debentures with proceeds from borrowings under the Corporation's
committed credit facility.
22. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
classifications, the most significant of which 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 of $12.5 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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