Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net
earnings attributable to common equity shareholders of $117 million, or $0.67
per common share, compared to $100 million, or $0.58 per common share, for the
first quarter of 2010.
Performance for the quarter was driven by the Corporation's regulated utilities
in western Canada.
Canadian Regulated Gas Utilities contributed earnings of $76 million, up $3
million from the first quarter of 2010. The improvement reflected growth in
utility infrastructure investment, reduced amortization costs and higher
capitalized finance charges, partially offset by the timing of and increase in
operating expenses. Due to the seasonality of the business, most of the earnings
of the gas utilities are realized in the first and fourth quarters. FortisBC's
gas business expects to file its 2012-2013 rate application this month.
"We are excited about the heightened focus on natural gas in North America,
especially regarding its potential use in the transportation sector," says Stan
Marshall, President and Chief Executive Officer, Fortis Inc.
Canadian Regulated Electric Utilities contributed earnings of $53 million, up
$13 million from the first quarter of 2010, mainly related to FortisAlberta and
FortisBC's electricity business. Earnings increased at FortisAlberta due to
growth in utility infrastructure investment, the timing of recording in 2010 the
cumulative impact of the 2010-2011 regulatory rate decision, a $1 million gain
on the sale of property and higher energy deliveries. The cumulative impact of
the 2010-2011 regulatory rate decision was recorded during the third quarter of
2010 when the decision was received. Earnings at FortisBC's electricity business
improved mainly as a result of growth in utility infrastructure investment and
higher electricity sales. Electricity sales during the first quarter of 2010
were lower than average due to warmer temperatures during that period. With
regard to regulatory matters, in March FortisAlberta filed its 2012-2013 rate
application, which includes proposed gross capital expenditures of more than
$775 million over the two-year period. FortisBC's electricity business expects
to file its 2012-2013 rate application this summer.
Caribbean Regulated Electric Utilities contributed $4 million, consistent with
earnings for the first quarter of 2010. There was no earnings' contribution from
Belize Electricity during the first quarter of 2011. In March the Supreme Court
of Belize dismissed Belize Electricity's appeal of the regulator's June 2008
Final Rate Decision. The Company is in the process of filing an appeal of the
trial judgment with the Belize Court of Appeal.
Non-Regulated Fortis Generation contributed $3 million to earnings, up $1
million from the first quarter of 2010 due to contribution from the Vaca
hydroelectric generating facility in Belize, which was commissioned in late
March 2010.
Fortis Properties delivered earnings of $1 million compared to $2 million for
the first quarter of 2010, reflecting lower occupancies at hotel operations in
western Canada and increased amortization costs due to ongoing capital
investment.
Corporate and other expenses were $20 million, $1 million lower quarter over
quarter mainly due to reduced operating expenses. Higher operating expenses
incurred in the first quarter of 2010 related to business development costs.
Common shareholders of Fortis received a dividend of 29 cents per common share
on March 1, 2011, up from 28 cents in the fourth quarter of 2010. The 3.6%
increase in the quarterly common share dividend translates to an annualized
dividend of $1.16 and extends the Corporation's record of annual common share
dividend increases to 38 consecutive years, the longest record of any public
corporation in Canada.
Consolidated capital expenditures, before customer contributions, were
approximately $233 million in the first quarter of 2011. Much of the
Corporation's consolidated capital expenditure program is being driven by the
regulated utilities in western Canada and the non-regulated Waneta hydroelectric
generation expansion project in British Columbia, in which Fortis holds a 51%
controlling interest. At FortisBC's gas business, construction of the liquefied
natural gas storage facility on Vancouver Island, at an estimated cost of $214
million, is expected to be completed in the next several weeks, with the
facility to be filled later in the year. The $110 million project to bring all
gas customer-care functions in-house with company-owned call centres and a new
customer information system should be in place by January 2012. FortisBC's
electricity business expects to substantially complete its $106 million Okanagan
Transmission Reinforcement Project in 2011. FortisAlberta has substantially
completed its $126 million Automated Meter Project, which involved the
replacement of approximately 466,000 conventional meters. Work continues on the
$900 million Waneta Expansion Project, which is expected to be completed in
spring 2015.
Cash flow from operating activities was $299 million for the quarter, up $98
million from the same quarter last year, driven by higher earnings, the
collection from customers of higher amortization costs and favourable changes in
working capital and regulatory deferral accounts.
"The most recent regulatory decisions received by our Canadian utilities provide
continuing stability in 2011," says Marshall. "Our utilities are focused on
operations and meeting the energy needs of customers. Our five-year capital
program, including the Waneta Expansion Project, is expected to total $5.5
billion, driving growth in earnings and dividends," he explains.
"Fortis continues to pursue acquisitions for profitable growth, focusing on
electric and gas utilities in the United States and Canada," concludes Marshall.
Interim Management Discussion and Analysis
For the three months ended March 31, 2011
Dated May 4, 2011
FORWARD-LOOKING STATEMENT
The following Management Discussion and Analysis ("MD&A") should be read in
conjunction with the Fortis Inc. ("Fortis" or the "Corporation") interim
unaudited consolidated financial statements and notes thereto for the three
months ended March 31, 2011 and the MD&A and audited consolidated financial
statements for the year ended December 31, 2010 included in the Corporation's
2010 Annual Report. The MD&A has been prepared in accordance with National
Instrument 51-102 - Continuous Disclosure Obligations. Financial information in
the MD&A 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
filing of regulatory applications and of receipt of regulatory decisions; the
expectation that cash required to complete subsidiary capital expenditure
programs will be sourced from a combination of cash from operations, borrowings
under credit facilities, equity injections from Fortis and long-term debt
issues; the expected timing of the close of the sale of the joint-use poles at
Newfoundland Power; consolidated forecast gross capital expenditures for 2011
and in total over the five-year period 2011 through 2015; the expectation that
the Corporation's significant capital program should drive growth in earnings
and dividends; expected consolidated long-term debt maturities and repayments on
average annually over the next five years; 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 2011; no expected material adverse credit rating actions in the
near term; the expectation that Fortis will become a U.S. Securities and
Exchange Commission Issuer by December 31, 2011;
and the expected impact of the transition to United States generally accepted
accounting principles. 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 material capital
project and financing cost overrun related to the construction of the Waneta
hydroelectric generation expansion project; no significant decline in capital
spending in 2011; 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 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;
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; capital project budget overrun,
completion and financing risk in the Corporation's non-regulated business;
economic conditions; capital resources and liquidity risk; weather and
seasonality; commodity price risk; derivative financial instruments and hedging;
interest rate risk; counterparty risk; competitiveness of natural gas; natural
gas supply; defined benefit pension plan performance and funding requirements;
risks related to the development of the FortisBC Energy (Vancouver Island) Inc.
franchise; environmental risks; insurance coverage risk; loss of licences and
permits; loss of service area; the risk of transition to new accounting
standards that do not recognize the impact of rate-regulation; 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 months ended March 31, 2011 and for the year ended December 31,
2010.
All forward-looking information in the MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, the Corporation
undertakes no obligation to revise or update any forward-looking information as
a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving
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, Canada. Fortis owns
non-regulated generation assets, primarily hydroelectric, across Canada and in
Belize and Upper New York State, and hotels and commercial office and retail
space primarily in Atlantic Canada. Year-to-date March 31, 2011, the
Corporation's electricity distribution systems met a combined peak demand of
approximately 5,014 megawatts ("MW") and its gas distribution system met a peak
day demand of 1,210 terajoules ("TJ"). For additional information on the
Corporation's business segments, refer to Note 1 to the Corporation's interim
unaudited consolidated financial statements for the three months ended March 31,
2011 and to the Corporate Overview section of the MD&A for the year ended
December 31, 2010.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably at the lowest reasonable cost and conduct business in an
environmentally responsible manner. The Corporation's main business, utility
operations, is highly regulated and the earnings of the Corporation's regulated
utilities are primarily determined under cost of service ("COS") regulation.
Generally under COS regulation, the respective regulatory authority sets
customer gas and electricity rates to permit a reasonable opportunity for the
utility to recover, on a timely basis, estimated costs of providing service to
customers, including a fair rate of return on a regulatory deemed or targeted
capital structure applied to an approved regulatory asset value ("rate base").
Generally, the ability of a regulated utility to recover prudently incurred
costs of providing service and to earn the regulatory approved rate of return on
common shareholders' equity ("ROE") and/or rate of return on rate base assets
("ROA") depends on the utility achieving the forecasts established in the
rate-setting processes. As such, earnings of regulated utilities are generally
impacted by: (i) changes in the regulator-approved allowed ROE or ROA; (ii)
changes in rate base; (iii) changes in energy sales or gas delivery volumes;
(iv) changes in the number and composition of customers; (v) variances between
actual expenses incurred and forecast expenses used to determine revenue
requirements and set customer rates; and (vi) timing differences, within an
annual financial reporting period, between when actual expenses are incurred and
when they are recovered from customers in rates. When forward test years are
used to establish revenue requirements and set base customer rates, these rates
are not adjusted as a result of actual COS being different from that which is
estimated, other than for certain prescribed costs that are eligible for
deferral account treatment. In addition, the Corporation's regulated utilities,
where applicable, are permitted by their respective regulatory authority to flow
through to customers, without markup, the cost of natural gas, fuel and/or
purchased power through customer rates and/or the use of rate stabilization and
other mechanisms.
Effective March 1, 2011, the Terasen Gas companies were renamed to commence
operating under a common brand identity with FortisBC in British Columbia,
Canada. As a result, Terasen Gas Inc. is now FortisBC Energy Inc. ("FEI"),
Terasen Gas (Vancouver Island) Inc. is now FortisBC Energy (Vancouver Island)
Inc. ("FEVI") and Terasen Gas (Whistler) Inc. is now FortisBC Energy (Whistler)
Inc. ("FEWI"), now collectively referred to as the FortisBC Energy companies.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirement, by the
nature of the assets. Key financial highlights for the first quarters ended
March 31, 2011 and March 31, 2010 are provided in the following table.
--------------------------------------------------------------------------
Consolidated Financial Highlights
(Unaudited) Quarter Ended March 31
($ millions, except for share data) 2011 2010 Variance
--------------------------------------------------------------------------
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Revenue 1,164 1,073 91
Energy Supply Costs 603 552 51
Operating Expenses 213 202 11
Amortization 103 94 9
Finance Charges 90 90 -
Corporate Taxes 30 28 2
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Net Earnings 125 107 18
--------------------------------------====================================
Net Earnings Attributable to:
Non-Controlling Interests 1 1 -
Preference Equity Shareholders 7 6 1
Common Equity Shareholders 117 100 17
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125 107 18
--------------------------------------====================================
Basic Earnings per Common Share ($) 0.67 0.58 0.09
Diluted Earnings per Common Share ($) 0.65 0.56 0.09
Weighted Average Number of Common
Shares Outstanding (millions) 175.0 171.6 3.4
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Cash Flow from Operating Activities 299 201 98
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Factors Contributing to Revenue Variance
Favourable
-- Gas and energy sales growth, mainly due to weather-related increases in
consumption, and growth in the number of customers mainly at
FortisAlberta
-- The timing of recording in 2010 the cumulative impact of revenue
requirements decisions received in 2010 at FortisAlberta and FEWI. The
impacts of the rate decisions were recorded during the third quarter of
2010 when the decisions were received.
-- An increase in gas delivery rates and the base component of electricity
rates at several of the utilities, reflecting ongoing investment in
utility capital assets and higher regulator-approved expenses
recoverable from customers
-- The flow through in customer electricity rates of higher energy supply
costs
-- An approximate $1 million gain on sale of property
-- Higher non-regulated hydroelectric generation in Belize
Unfavourable
-- Approximately $4 million unfavourable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar quarter over
quarter
Factors Contributing to Energy Supply Costs Variance
Unfavourable
-- Gas and energy sales growth
-- Higher energy supply costs associated with increased fuel costs, and the
operation of the Energy Cost Adjustment Mechanism ("ECAM") regulatory
deferral account at Maritime Electric
Favourable
-- Approximately $3 million associated with favourable foreign currency
translation
Factors Contributing to Operating Expenses Variance
Unfavourable
-- Higher operating expenses at Newfoundland Power, mainly due to the
regulatory approved change in the accounting treatment for other post-
employment benefit ("OPEB") costs and increased maintenance costs, due
to higher capital work performed in the first quarter of 2010
-- Wage and general inflationary increases
-- The timing of and a regulatory approved increase in certain operating
expenses at the FortisBC Energy companies
Favourable
-- Higher corporate operating expenses incurred in the first quarter of
2010 related to business development costs
Factors Contributing to Amortization Costs Variance
Unfavourable
-- Higher amortization rates at FortisAlberta, due to the timing of
recording in 2010 the cumulative impact of the revenue requirements
decision received in 2010. The impacts of the rate decision were
recorded during the third quarter of 2010 when the decision was
received.
-- Continued investment in utility capital assets and income producing
properties
Favourable
-- Reduced amortization costs during the first quarter of 2011 at the
FortisBC Energy companies due to the retirement late in 2010 of certain
general plant assets
-- Increased amortization costs during the first quarter of 2010 at
Newfoundland Power due to an approximate $1 million adjustment, as
approved by the regulator, related to an amortization study
Factors Contributing to Finance Charges Variance
Favourable
-- The refinancing of maturing corporate debt at a lower rate
-- Higher capitalized allowance for funds used during construction
Unfavourable
-- Higher debt levels in support of the utilities' capital expenditure
programs
Factors Contributing to Corporate Taxes Variance
Unfavourable
-- Higher earnings before corporate taxes
Favourable
-- Lower effective corporate income tax rate, driven by an overall increase
in deductible expenses for income tax purposes compared to accounting
purposes and lower statutory income tax rates
Factors Contributing to Earnings Variance
Favourable
-- The approximate $4.5 million earnings impact of rate base growth, mainly
at the regulated utilities in western Canada, due to continued
investment in utility capital assets
-- Higher energy sales, driven by FortisBC Electric and FortisAlberta
-- The timing of recording in 2010 the cumulative impact of revenue
requirements decisions received in 2010 at FortisAlberta and FEWI. The
impacts of the rate decisions were recorded during the third quarter of
2010 when the decisions were received.
-- Higher corporate operating expenses incurred in the first quarter of
2010 related to business development costs
-- A $1 million gain on the sale of property
-- Higher non-regulated hydroelectric generation in Belize
Unfavourable
-- The timing of and a regulatory approved increase in certain operating
expenses at the FortisBC Energy companies
SEGMENTED RESULTS OF OPERATIONS
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Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited) Quarter Ended March 31
($ millions) 2011 2010 Variance
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Regulated Gas Utilities - Canadian
FortisBC Energy Companies 76 73 3
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Regulated Electric Utilities -
Canadian
FortisAlberta 21 14 7
FortisBC Electric 19 14 5
Newfoundland Power 7 7 -
Other Canadian 6 5 1
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53 40 13
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Regulated Electric Utilities -
Caribbean 4 4 -
Non-Regulated - Fortis Generation 3 2 1
Non-Regulated - Fortis Properties 1 2 (1)
Corporate and Other (20) (21) 1
--------------------------------------------------------------------------
Net Earnings Attributable to Common
Equity Shareholders 117 100 17
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For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Corporation's regulated utilities, refer to
the "Regulatory Highlights" section of this MD&A. A discussion of the financial
results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
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Gas Volumes by Major Customer
Category (Unaudited) Quarter Ended March 31
(TJ) 2011 2010 Variance
--------------------------------------------------------------------------
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Core - Residential and Commercial 50,448 40,431 10,017
Industrial 1,888 1,675 213
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Total Sales Volumes 52,336 42,106 10,230
Transportation Volumes 20,484 16,410 4,074
Throughput under Fixed Revenue
Contracts 476 4,392 (3,916)
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Total Gas Volumes 73,296 62,908 10,388
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(1) Formerly referred to as the Terasen Gas companies, the FortisBC Energy
companies are comprised of FortisBC Energy Inc. ("FEI"), FortisBC Energy
(Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc.
("FEWI").
Factors Contributing to Gas Volumes Variance
Favourable
-- Higher average consumption by residential and commercial customers as a
result of cooler weather
-- Higher transportation volumes reflecting improving economic conditions
which is favourably affecting the forestry sector
Unfavourable
-- Lower volumes under fixed revenue contracts, mainly due to higher
precipitation, which made it more cost efficient for a large customer to
not utilize its natural gas-powered generating facility during the first
quarter of 2011
Net customer additions were 1,373 during the first quarter of 2011 compared to
1,566 during the same quarter of 2010. Gross customer additions decreased due to
lower building activity during 2011.
Seasonality has a material impact on the earnings of the FortisBC Energy
companies as a major portion of the gas distributed is used for space heating.
Most of the annual earnings of the FortisBC Energy companies are realized in the
first and fourth quarters.
The FortisBC Energy 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 forecast to set gas rates do not materially affect
earnings.
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Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
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Revenue 575 526 49
Earnings 76 73 3
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Factors Contributing to Revenue Variance
Favourable
-- Higher average gas consumption
-- An increase in the delivery component of customer rates, mainly due to
ongoing investment in utility capital assets and higher regulatory
approved operating expenses recoverable from customers
Factors Contributing to Earnings Variance
Favourable
-- Rate base growth, due to continued investment in utility capital assets
-- The timing of recording in 2010 the cumulative impact of a revenue
requirements decision received in 2010 at FEWI. The impacts of the
decision were recorded during the third quarter of 2010 when the
decision was received.
-- Reduced amortization costs during the first quarter of 2011 due to the
retirement late in 2010 of certain general plant assets
-- Higher capitalized allowance for funds used during construction related
to the construction of the Mount Hayes liquefied natural gas ("LNG")
storage facility
Unfavourable
-- The timing of and a regulatory approved increase in operating expenses,
driven by labour and benefits costs and consulting expenses
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
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Energy Deliveries (gigawatt hours
("GWh")) 4,402 4,109 293
Revenue ($ millions) 103 87 16
Earnings ($ millions) 21 14 7
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Factors Contributing to Energy Deliveries Variance
Favourable
-- Increased average consumption due to cooler-than-normal temperatures,
and increased activity in the oil and gas sector due to improved market
prices for oil
-- Customer growth, with the total number of customers increasing by
approximately 10,800 quarter over quarter
As a significant portion of FortisAlberta's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue. Revenue is a
function of numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Revenue Variance
Favourable
-- A 4.7% increase in base customer electricity distribution rates over
final approved 2010 rates, effective January 1, 2011, associated with
the 2010-2011 regulatory rate decision. The increase in base rates was
primarily due to ongoing investment in utility capital assets and higher
regulator-approved finance charges recoverable from customers.
-- Revenue for the first quarter of 2010 reflected a 7.5% interim customer
rate increase whereas revenue for the first quarter of 2011 reflected
the full impact of approved rate increases as provided in the 2010-2011
regulatory rate decision. The cumulative impact from January 1, 2010 of
the rate decision was recorded during the third quarter of 2010 when the
decision was received. The final approved customer rate increase for
2010 was 20.1%.
-- An approximate $1 million gain on sale of property
-- Growth in the number of customers
Factors Contributing to Earnings Variance
Favourable
-- Rate base growth, due to continued investment in utility capital assets
-- The timing of recording in 2010 the cumulative impact of the 2010-2011
regulatory rate decision, as discussed above
-- The $1 million gain on the sale of property
-- Higher energy deliveries
FORTISBC ELECTRIC (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales (GWh) 905 820 85
Revenue ($ millions) 83 72 11
Earnings ($ millions) 19 14 5
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(1) Formerly referred to as FortisBC, and 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.
Factors Contributing to Electricity Sales Variance
Favourable
-- Lower average consumption during the first quarter of 2010 due to
warmer-than-normal temperatures experienced during that period
-- Growth in the number of residential and general service customers
Factors Contributing to Revenue Variance
Favourable
-- The 10.4% increase in electricity sales
-- A 6.6% increase in customer electricity rates, effective January 1,
2011, mainly reflecting ongoing investment in utility capital assets and
the higher cost of capital
-- A 2.9% increase in customer electricity rates, effective September 1,
2010, as a result of the flow through to customers of increased
purchased power costs charged by BC Hydro
Unfavourable
-- Increased performance-based rate-setting ("PBR") incentive adjustments
owing to customers
-- Lower pole attachment revenue, partially offset by higher wheeling
revenue
Factors Contributing to Earnings Variance
Favourable
-- Electricity sales growth
-- Rate base growth, due to continued investment in utility capital assets
NEWFOUNDLAND POWER
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales (GWh) 1,834 1,795 39
Revenue ($ millions) 183 178 5
Earnings ($ millions) 7 7 -
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Factors Contributing to Electricity Sales Variance
Favourable
-- Growth in the number of customers and higher average consumption
Factors Contributing to Revenue Variance
Favourable
-- The 2.2% increase in electricity sales
-- An overall average 0.8% increase in customer electricity rates,
effective January 1, 2011, mainly reflecting higher OPEB costs,
partially offset by a decrease in the allowed ROE to 8.38% for 2011,
down from 9.00% for 2010
Factors Contributing to Earnings Variance
Unfavourable
-- The decrease in the allowed ROE, as reflected in customer rates
-- Higher maintenance costs as a result of higher capital work performed in
the first quarter of 2010, due to an early start of the capital program
and restoration work related to an ice storm in March 2010
-- Timing of labour costs in 2011, as a significant portion of certain
employee initiatives were completed during the first quarter of 2011
Favourable
-- Electricity sales growth
OTHER CANADIAN ELECTRIC UTILITIES (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales (GWh) 654 632 22
Revenue ($ millions) 91 82 9
Earnings ($ millions) 6 5 1
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(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Electricity Sales Variance
Favourable
-- Higher average consumption, reflecting colder temperatures in Ontario
and on Prince Edward Island ("PEI")
Factors Contributing to Revenue Variance
Favourable
-- The 3.5% increase in electricity sales
-- An increase in the recovery from customers of the ECAM regulatory
deferral account
-- An average 3.8% increase in customer electricity rates at Algoma Power,
effective December 1, 2010, reflecting an increase in the allowed ROE to
9.85% for 2011 from 8.57% for 2010 and the use of a forward test year
for rate setting
-- Increases in the base component of customer electricity distribution
rates at Fort Erie, Gananoque and Port Colborne in Ontario, effective
May 1, 2010
Unfavourable
-- A 14% decrease in customer rates, effective March 1, 2011, reflecting
the impact of the PEI Energy Accord (the "Accord") with the Government
of PEI, including the flow through to customers of lower purchased power
costs as a result of a new five-year purchase power agreement between
Maritime Electric and New Brunswick Power ("NB Power")
Factors Contributing to Earnings Variance
Favourable
-- A higher allowed ROE at Algoma Power, as reflected in customer rates
-- Electricity sales growth
-- A deferred start to the vegetation management program in 2011
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate (2) 0.99 1.04 (0.05)
Electricity Sales (GWh) 257 256 1
Revenue ($ millions) 76 76 -
Earnings ($ millions) 4 4 -
----------------------------------------------------------------------------
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(1) Includes Belize Electricity, in which Fortis holds an approximate 70%
controlling interest; Caribbean Utilities on Grand Cayman, Cayman Islands,
in which Fortis holds an approximate 59% controlling interest; and wholly
owned 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 Electricity Sales Variance
Favourable
-- Warmer and drier weather conditions experienced on Grand Cayman, which
increased air conditioning load
-- Growth in the number of customers on Grand Cayman
Unfavourable
-- Cooler weather conditions experienced in the Turks and Caicos Islands,
which decreased air conditioning load
-- The loss at Belize Electricity of a large industrial customer that began
generating its own electricity
-- Tempered growth due to continuing challenging economic conditions in the
region
Factors Contributing to 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
-- Increased electricity sales on Grand Cayman
-- Higher miscellaneous revenue at Fortis Turks and Caicos
Unfavourable
-- Approximately $4 million unfavourable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar quarter over
quarter
Factors Contributing to Earnings Variance
Favourable
-- Increased electricity sales on Grand Cayman
-- Lower operating maintenance expenses at Caribbean Utilities, due to
various capital upgrade projects occurring during the first quarter of
2011
-- Higher miscellaneous revenue
-- Ongoing efforts to reduce costs and improve efficiencies to temper the
impact of continuing challenging economic conditions in the region
Unfavourable
-- Higher provision for bad debts at Belize Electricity due to a large
industrial customer entering into receivership in the fourth quarter of
2010
-- Higher finance charges at Belize Electricity due to interest expense on
regulatory liabilities
NON-REGULATED - FORTIS GENERATION (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Sales (GWh) 76 67 9
Revenue ($ millions) 7 5 2
Earnings ($ millions) 3 2 1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New York
State, with a combined generating capacity of 139 megawatts, mainly
hydroelectric. Results reflect contribution from the Vaca hydroelectric
generating facility in Belize from late March 2010 when the facility was
commissioned.
Factors Contributing to Energy Sales Variance
Favourable
-- Increased production driven by the Vaca hydroelectric generating
facility in Belize, which was commissioned in late March 2010
Factors Contributing to Revenue Variance
Favourable
-- Higher production in Belize
-- Higher average energy sales rate per megawatt hour in Ontario of $72.59
for the first quarter of 2011 compared to $33.85 for the same period in
2010. Effective May 1, 2010, energy produced in Ontario is being sold
under a fixed-price contract. Previously, energy was sold at market
rates.
Factors Contributing to Earnings Variance
Favourable
-- Higher production in Belize
-- Higher average energy sales rates in Ontario
Unfavourable
-- Higher finance charges as a result of lower interest revenue associated
with inter-company lending to regulated operations in Ontario
NON-REGULATED - FORTIS PROPERTIES (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Hospitality Revenue 33 33 -
Real Estate Revenue 17 16 1
--------------------------------------------------------------------------
Total Revenue 50 49 1
--------------------------------------------------------------------------
Earnings 1 2 (1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Fortis Properties owns and operates 21 hotels, comprised of more than
4,100 rooms, in eight Canadian provinces and approximately 2.7 million
square feet of commercial office and retail space primarily in Atlantic
Canada.
Factors Contributing to Revenue Variance
Favourable
-- A $0.5 million gain on the sale of the Viking Mall in Newfoundland
during the first quarter of 2011
-- Revenue growth at all regions of the Real Estate Division, mainly due to
rent increases
-- A 0.6% increase in revenue per available room ("RevPAR") at the
Hospitality Division to $63.29 for the first quarter of 2011 from $62.93
for the same quarter in 2010. RevPAR increased due to an overall 1.6%
increase in the average room rate, partially offset by an overall 1%
decrease in hotel occupancy. The average room rate increased in all
regions, lead by operations in Atlantic Canada. Hotel occupancy at
operations in western Canada decreased, while occupancy at operations in
Atlantic Canada and central Canada increased.
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division to 94.3% as
at March 31, 2011 from 95.8% as at March 31, 2010
Factors Contributing to Earnings Variance
Unfavourable
-- Lower performance at hotel operations, primarily due to the continued
unfavourable impact of the economic downturn
-- Higher amortization costs due to capital investment in both the
Hospitality and Real Estate Divisions
Favourable
-- Improved performance at real estate operations, primarily due to the
gain on sale of the Viking Mall
CORPORATE AND OTHER (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 7 7 -
Operating Expenses 2 4 (2)
Amortization 2 3 (1)
Finance Charges (2) 19 20 (1)
Corporate Tax Recovery (3) (5) 2
---------------------------------------
(13) (15) 2
Preference Share Dividends 7 6 1
--------------------------------------------------------------------------
Net Corporate and Other Expenses (20) (21) 1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
FortisBC Holdings Inc. ("FHI") (formerly Terasen Inc.) corporate-related
activities and the financial results of FHI's 30% ownership interest in
CustomerWorks Limited Partnership and of FHI's non-regulated wholly owned
subsidiary FortisBC Alternative Energy Services Inc. (formerly Terasen
Energy Services Inc.)
(2) Includes dividends on preference shares classified as long-term
liabilities
Factors Contributing to Net Corporate and Other Expenses Variance
Favourable
-- Reduced operating expenses. Operating expenses were higher during the
first quarter of 2010 due to business development costs incurred during
that period.
-- Lower finance charges driven by the redemption of $125 million 8.0%
Capital Securities in April 2010, partially offset by higher average
credit facility borrowings combined with higher interest rates charged
on those credit facility borrowings
-- Lower amortization costs, due to the retirement of some assets at
CustomerWorks Limited Partnership during 2010
Unfavourable
-- Lower corporate tax recovery, mainly due to a lower net loss for income
tax purposes
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series H on January 18, 2010
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the first quarter of 2011 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
Customer
2009 2010 2011 Rates
----------------------------------------------------------------------------
ROE COS/ROE
----------------------------
FEI British 8.47 FEI: Prior
Columbia (2) 9.50 9.50 to January
Utilities 40 (1) /9.50 1, 2010,
Commission (3) 50/50
("BCUC") sharing of
earnings
above or
below the
allowed ROE
under a PBR
mechanism
that expired
on December
31, 2009
with a two-
year phase-
out
FEVI BCUC 40 9.17 10.00 10.00 ROEs
(2) established
/10.00 by the BCUC,
(3) effective
July 1,
2009, as a
result of a
cost of
capital
decision in
the fourth
quarter of
2009.
FEWI BCUC 40 8.97 10.00 10.00 Previously,
(2) the allowed
/10.00 ROEs were
(3) set using an
automatic
adjustment
formula tied
to long-term
Canada bond
yields.
------------
Future Test
Year
----------------------------------------------------------------------------
FortisBC BCUC 40 8.87 9.90 9.90 COS/ROE
Electric
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
----------------------------------------------------------------------------
FortisAlberta Alberta 41 9.00 9.00 9.00 (4) COS/ROE
Utilities
Commission ROE
("AUC") established
by the AUC,
effective
January 1,
2009, as a
result of a
generic cost
of capital
decision in
the fourth
quarter of
2009.
Previously,
the allowed
ROE was set
using an
automatic
adjustment
formula tied
to long-term
Canada bond
yields.
------------
Future Test
Year
----------------------------------------------------------------------------
Newfoundland Newfoundland 45 8.95 9.00 8.38 COS/ROE
Power and Labrador +/- +/- +/-
Board of 50 bps 50 bps 50 bps ROE for 2010
Commissioners established
of Public by the PUB.
Utilities Except for
("PUB") 2010, the
allowed ROE
is set using
an automatic
adjustment
formula tied
to long-term
Canada bond
yields.
------------
Future Test
Year
----------------------------------------------------------------------------
Maritime Island 40 9.75 9.75 9.75 COS/ROE
Electric Regulatory
and Appeals
Commission
("IRAC")
------------
Future Test
Year
----------------------------------------------------------------------------
ROE
---------------------------
Fortis Ontario 40 (5) 8.01 8.01 8.01 Canadian
Ontario Energy Board Niagara Power
("OEB") - COS/ROE
Canadian
Niagara
Power
Algoma Power 50 (6) 8.57 8.57 9.85 (7) Algoma Power
/40 (7) - COS/ROE and
subject to
Rural and
Remote Rate
Protection
("RRRP")
Program
Franchise Cornwall
Agreement Electric -
Cornwall Price cap
Electric with
commodity
cost flow
through
-------------
Canadian
Niagara Power
- 2009 test
year for
2009, 2010
and 2011
Algoma Power
- 2007
historical
test year for
2009 and
2010; 2011
test year for
2011
----------------------------------------------------------------------------
ROA
---------------------------
Belize Public N/A - (8) - (8) - (8) Four-year
Electricity Utilities COS/ROA
Commission agreements
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 - 7.75 - 7.75 - COS/ROA
Utilities Regulatory 11.00 9.75 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 to If the actual
the Governor ROA is lower
than the
allowed ROA,
due to
additional
costs
resulting
from a
hurricane or
other event,
the Company
may apply for
an increase
in customer
rates in the
following
year.
-------------
Future Test
Year
----------------------------------------------------------------------------
(1) Effective January 1, 2010. For 2009, the allowed common equity component
of capital structure was 35%.
(2) Pre-July 1, 2009
(3) Effective July 1, 2009
(4) Interim pending finalization by the AUC
(5) Effective May 1, 2010. For 2009, effective May 1, the allowed common
equity component of capital structure was 43.3%.
(6) Pre-December 1, 2010
(7) Effective December 1, 2010
(8) Allowed ROA to be settled once regulatory matters are resolved.
(9) Amount provided under licence. ROA achieved in 2009 and 2010 was
materially lower than the ROA allowed under the licence. Fortis Turks and
Caicos had requested a review of its rates in 2010.
----------------------------------------------------------------------------
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
--------------------------------------------------------------------------
Regulated Utility Summary Description
--------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review natural gas and propane
commodity and mid-stream rates with the BCUC every
three months 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 propane and mid-
stream costs are flowed through to customers
without markup. The delivery rate charged to FEVI
customers includes a component to recover approved
gas costs and is set annually. In order to ensure
that the balances in the Commodity Cost
Reconciliation Account and Mid-stream Cost
Reconciliation Account are recovered on a timely
basis, FEI and FEWI prepare and file quarterly
calculations with the BCUC to determine whether
customer rate adjustments are needed to reflect
prevailing market prices for natural gas. These
rate adjustments ignore the temporal effect of
derivative valuation adjustments on the balance
sheet and, instead, reflect the forward forecast of
gas costs over the recovery period.
- Effective January 1, 2011, rates for residential
customers in the Lower Mainland, Fraser Valley,
Interior, North and Kootenay service areas
decreased by approximately 6%, as approved by the
BCUC, to reflect net changes in delivery, commodity
and mid-stream costs. Rates remained unchanged as
of April 1, 2011.
- In December 2010 FEI filed an application with
the BCUC to provide fuelling services through FEI-
owned and operated compressed natural gas and LNG
fuelling stations. If the application is approved,
commercial customers will be able to safely and
economically refuel their fleet vehicles on their
own premises, at rates regulated by the BCUC, using
stations provided by FEI.
- FEI, FEVI and FEWI 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. The companies are expecting to
bring forth an application during 2011.
- In January 2011 FEI filed its review of the Price
Risk Management Plan ("PRMP") objectives with the
BCUC related to its gas commodity hedging plan and
also submitted a 2011-2014 PRMP. On a partial
basis, the BCUC has approved FEI to implement
portions of its 2011-2014 PRMP. FEVI plans to file
an updated PRMP by June 2011.
- The FortisBC Energy companies expect to file
2012-2013 Revenue Requirements Applications in May
2011.
--------------------------------------------------------------------------
FortisBC Electric - In December 2010 the BCUC approved a Negotiated
Settlement Agreement ("NSA") pertaining to FortisBC
Electric's 2011 Revenue Requirements Application.
The result was a general customer electricity rate
increase of 6.6%, effective January 1, 2011. The
rate increase was primarily the result of the
Company's ongoing investment in utility capital
assets and the higher cost of capital.
- FortisBC Electric expects to file a 2012-2013
Revenue Requirements Application in summer 2011.
--------------------------------------------------------------------------
FortisAlberta - In December 2010 the AUC issued its decision on
FortisAlberta's August 2010 Compliance Filing,
which incorporated the AUC's decision, received in
July 2010, on the Company's 2010 and 2011
Distribution Tariff Application ("DTA"). The
December 2010 decision approved the Company's
distribution revenue requirements of $368 million
for 2011. Final distribution electricity rates and
rate riders were also approved, effective January
1, 2011.
- During the first quarter of 2011, the AUC
initiated its proceeding to finalize the allowed
ROE for 2011, review capital structure and consider
whether a return to a formula-based approach for
annually setting the allowed ROE, beginning in
2012, is warranted. In the absence of a formula-
based approach, the AUC is expected to consider how
the allowed ROE will be set for 2012. A hearing on
the proceeding is expected to commence in the
second quarter of 2011.
- In March 2011 FortisAlberta filed its 2012 and
2013 DTA. The Company has requested approval of
revenue requirements of $410 million for 2012 and
$447 million for 2013, for rate increases of 8.2%
and 6.9%, respectively. The DTA also proposes
approximately $776 million in gross capital
expenditures over the two-year period. The rate
increases are driven primarily by rate base growth
associated with capital expenditures, which results
in increased amortization costs and interest
expense. The Company has proposed a schedule for
the DTA proceeding that would include a hearing in
late October 2011 with a final decision expected in
the first quarter of 2012.
- The AUC has initiated a proceeding in respect of
FortisAlberta's Review and Variance Application to
determine the prudence of the additional capital
expenditures above $104 million related to the
Company's Advanced Metering Project. The total
project cost is expected to be approximately $126
million. A decision by the AUC is expected in the
second quarter of 2011.
- In October 2010 the Central Alberta Rural
Electrification Association ("CAREA") filed an
application with the AUC seeking a declaration
that, effective January 1, 2012, CAREA be entitled
to service any new customer wishing to obtain
electricity for use on property within CAREA's
service area and that FortisAlberta be restricted
to serving only those customers that are not being
provided service by CAREA. FortisAlberta has
intervened in the proceeding.
--------------------------------------------------------------------------
- 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 electricity rates.
FortisAlberta is currently assessing PBR and will
participate fully in the AUC process.
--------------------------------------------------------------------------
Newfoundland - In November 2010 the PUB approved Newfoundland
Power Power's application to defer the recovery of
expected increased costs of $2.4 million, due to
expiring regulatory amortizations, in 2011.
- In December 2010 the PUB approved Newfoundland
Power's application to: (i) adopt the accrual
method of accounting for OPEB costs, effective
January 1, 2011; (ii) recover the transitional
regulatory asset balance of approximately $53
million, associated with adoption of accrual
accounting, over a 15-year period; and (iii) adopt
an OPEB cost-variance deferral account to capture
differences between OPEB expense calculated in
accordance with Canadian GAAP and OPEB expense
approved by the PUB for rate-setting purposes.
- In December 2010 Newfoundland Power received
approval from the PUB for an overall average 0.8%
increase in customer electricity rates, effective
January 1, 2011, mainly resulting from the PUB's
approval for the Company to change its accounting
for OPEB costs, as described above, partially
offset by the impact of the decrease in the allowed
ROE for 2011.
- On January 1, 2011, new support structure
arrangements with Bell Aliant went into effect.
Bell Aliant will buy back 40% of all joint-use
poles and related infrastructure owned by
Newfoundland Power for approximately $46 million.
The support structure arrangements are subject to
certain conditions, including PUB approval of the
sale of 40% of the Company's joint-use poles, which
must be met by both parties by June 30, 2011, or
either party may choose to terminate. In the event
of termination, the rights and recourses under the
original Joint-Use Facilities Partnership Agreement
will remain in effect for both parties.
Newfoundland Power filed an application with the
PUB in February 2011 requesting approval of the
transaction and expects the transaction to close in
2011. Newfoundland Power anticipates the proceeds
from the sale of the poles will be used to pay down
credit facility borrowings and maintain the
utility's capital structure at 45% common equity.
- The Company is currently assessing the
requirement for it to file an application with the
PUB to recover expected increased costs in 2012.
- In April 2011 the PUB approved Newfoundland
Power's application requesting an optional seasonal
rate for domestic customers effective July 1, 2011.
This optional seasonal rate charges a higher price
for electricity consumed during the months of
December through April and a lower rate during the
months of May through November. The PUB also
approved the use of an Optional Rates Revenue and
Cost Recovery Account that provides for the
deferral of annual cost and revenue effects
associated with implementing optional seasonal
rates.
- An application is expected to be filed by the
Company in May 2011 seeking an increase in customer
rates of approximately 8%, effective July 1, 2011.
The proposed increase in rates is mainly due to 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 electricity that Newfoundland
Hydro sells to Newfoundland Power are captured and
flowed through to Newfoundland Power customers
through the operation of Newfoundland Power's Rate
Stabilization Account. The proposed increase in
rates is principally due to increased fuel prices.
--------------------------------------------------------------------------
Maritime Electric - In November 2010 Maritime Electric signed the
Accord with the Government of PEI. The Accord
covers the period from March 1, 2011 through
February 29, 2016. Under the terms of the Accord,
the Government of PEI is assuming responsibility
for the cost of replacement energy and the monthly
operating and maintenance costs related to the NB
Power Point Lepreau Nuclear Generating Station
("Point Lepreau"), effective March 1, 2011 until
Point Lepreau is fully refurbished, which is
expected by fall 2012. The Government of PEI is
financing these costs, which will be recovered from
customers beginning when Point Lepreau returns to
service. In the event that Point Lepreau does not
return to service by fall 2012, the Government of
PEI reserves the right to cease the monthly
payments. As permitted by IRAC, replacement energy
costs incurred during the refurbishment of Point
Lepreau up to the end of February 2011 were
deferred by Maritime Electric and totalled
approximately $47 million. The deferred costs are
included in rate base and are, therefore, earning a
return. The nature and timing of the recovery of
the deferred costs is subject to further review by
a commission to be established by the Government of
PEI. The Accord also provides for the financing by
the Government of PEI of costs associated with
Maritime Electric's termination of the Dalhousie
Unit Participation Agreement. The costs will be
subsequently collected from customers over a period
to be established by the Government of PEI. As a
result of the Accord, including the favourable
impact on purchased power costs of the new five-
year power purchase agreement between Maritime
Electric and NB Power, customer electricity rates
decreased by approximately 14.0% effective March 1,
2011, at which time a two-year customer rate freeze
commenced.
--------------------------------------------------------------------------
FortisOntario - In non-rebasing years, customer electricity
distribution rates are set using inflationary
factors less an efficiency target under the Third-
Generation Incentive Rate Mechanism ("IRM") as
prescribed by the OEB. In March 2011 the OEB
published the applicable inflationary and
efficiency targets, which resulted in minimal
changes in base customer electricity distribution
rates at FortisOntario's operations Fort Erie,
Gananoque and Port Colborne.
- In November 2010 the OEB approved an NSA
pertaining to Algoma Power's electricity
distribution rate application for customer rates,
effective December 1, 2010 through December 31,
2011, using a 2011 forward test year. The rates
reflect an approved allowed ROE of 9.85% on a
deemed equity component of capital structure of
40%. The overall impact of the OEB rate decision
on an average customer's electricity bill was an
increase of 3.8%, including rate riders and other
charges.
- The present form of Third-Generation IRM will not
accommodate Algoma Power's customer rate structure
and the RRRP Program; therefore, Algoma Power has
agreed to consult with interveners to develop a
form of incentive rate-making that may be used
between rebasing periods. Due to regulations in
Ontario associated with the RRRP Program, customer
electricity distribution rates at Algoma Power are
tied to the average changes in rates of other
electric utilities in Ontario. Pending these
consultations, Algoma Power will file for incentive
rate-making for customer electricity distribution
rates, effective January 1, 2012.
- FortisOntario expects to file a COS Application
in 2012 for harmonized electricity distribution
rates in Fort Erie, Port Colborne and Gananoque,
effective January 1, 2013, using a 2013 forward
test year. The timing of the filing of the COS
Application corresponds with the ending of the
period that the current Third-Generation IRM
applies to FortisOntario.
--------------------------------------------------------------------------
Belize Electricity - In March 2011 the Supreme Court of Belize
dismissed Belize Electricity's appeal of the
regulator's June 2008 Final Rate Decision. The
Company is in the process of filing an appeal of
the trial judgment with the Belize Court of Appeal
and has filed an application to restrain the
regulator from initiating any rate action pending
the hearing and determination of the appeal.
--------------------------------------------------------------------------
Caribbean Utilities - In March 2011 after the requisite review,
Caribbean Utilities confirmed to the ERA that the
RCAM, as provided in the Company's transmission and
distribution licence, yielded no customer rate
adjustment effective June 1, 2011.
- In March 2011 the ERA approved US$134 million of
proposed non-generation installation expenditures
as requested by Caribbean Utilities in its 2011-
2015 Capital Investment Plan ("CIP"). The 2011-
2015 CIP was prepared upon the basis of the
Company's application to the ERA for a delay in any
new generation installation until there is more
certainty in growth forecasts. The remaining US$85
million of the CIP relates to new generation
installation, which would be subject to a
competitive solicitation process with the next
generating unit currently scheduled for
installation in 2014.
--------------------------------------------------------------------------
Fortis Turks - In March 2011 Fortis Turks and Caicos submitted
and Caicos its 2010 annual regulatory filing outlining the
Company's performance in 2010. Included in the
filing were the calculations, in accordance with
the utility's licence, of rate base for 2010 of
US$142 million and cumulative shortfall in
achieving allowable profits as at December 31, 2010
of US$49 million.
- Fortis Turks and Caicos intends to submit a new
Rate Variation Application in 2011, which takes
into account changes in the utility's rate base and
in the local business and regulatory environment
since filing its 2010 application. The 2010
application was not accepted by the Governor of the
Turks and Caicos Islands due to concern about the
impact a proposed rate increase might have on key
sectors of the local economy.
--------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between March 31, 2011 and December 31, 2010.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
March 31, 2011 and December 31, 2010
--------------------------------------------------------------------------
Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
--------------------------------------------------------------------------
Accounts 45 The increase was primarily due to the
receivable impact of a seasonal increase in sales and
the operation of the equal payment plans
for customers mainly at the FortisBC
Energy companies and Newfoundland Power,
partially offset by the lower commodity
cost of natural gas reflected in customer
rates at the FortisBC Energy companies.
--------------------------------------------------------------------------
Inventories (80) The decrease was driven by the normal
seasonal reduction of gas in storage at
the FortisBC Energy companies, due to
higher consumption during the winter
months.
--------------------------------------------------------------------------
Utility capital 149 The increase primarily related to $219
assets million invested in electricity and gas
systems, partially offset by amortization
and customer contributions for the three
months ended March 31, 2011.
--------------------------------------------------------------------------
Short-term (99) The decrease was driven by lower
borrowings borrowings at the FortisBC Energy
companies due to seasonality of
operations.
--------------------------------------------------------------------------
Regulatory 71 The increase was driven by deferrals at
liabilities - the FortisBC Energy companies associated
current and long- with an increase in the Rate Stabilization
term Deferral Account ("RSDA"), reflecting the
accumulation of over-recovered costs of
providing service to customers during the
first quarter of 2011, and an increase in
the Mid-stream Cost Reconciliation
Account, as amounts collected in customer
rates were in excess of actual mid-stream
gas-delivery costs.
--------------------------------------------------------------------------
Shareholders' 92 The increase was due to net earnings
equity attributable to common equity shareholders
for the three months ended March 31, 2011,
less common share dividends, and the
issuance of common shares under the
Corporation's share purchase, dividend
reinvestment and stock option plans,
partially offset by an increase in
accumulated other comprehensive loss.
--------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the first quarter of 2011, as compared to the first quarter of 2010,
followed by a discussion of the nature of the variances in cash flows quarter
over quarter.
--------------------------------------------------------------------------
Summary of Consolidated Cash Flows
(Unaudited) Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Cash, Beginning of Period 109 85 24
Cash Provided by (Used in):
Operating Activities 299 201 98
Investing Activities (219) (176) (43)
Financing Activities (103) (17) (86)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents - (1) 1
--------------------------------------------------------------------------
Cash, End of Period 86 92 (6)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $98 million higher quarter over quarter. The increase
was primarily due to: (i) higher earnings; (ii) the collection from customers of
increased amortization costs, mainly at FortisAlberta, as approved by the
regulator; and (iii) favourable changes in working capital and regulatory
deferral accounts. The favourable working capital changes were driven by greater
impacts of seasonality at the FortisBC Energy companies and higher Alberta
Electric System Operator net transmission-related receipts and payments at
FortisAlberta. The favourable changes in regulatory deferral accounts related
mainly to the increase in the RSDA at the FortisBC Energy companies, due to the
accumulation of over-recovered costs of providing service to customers during
2011.
Investing Activities: Cash used in investing activities was $43 million higher
quarter over quarter, driven by capital spending related to the non-regulated
Waneta hydroelectric generation expansion project (the "Waneta Expansion
Project") and higher capital expenditures at FortisAlberta.
Financing Activities: Cash used in financing activities was $86 million higher
quarter over quarter. Lower proceeds from the issuance of preference shares were
partially offset by lower repayments of short-term borrowings and long-term
debt, higher net borrowings under committed credit facilities and higher
advances from non-controlling interests.
Net repayments of short-term borrowings were $83 million lower quarter over
quarter. The net repayments during the first quarter of 2010 increased due to
FEI using proceeds from an equity injection by the Corporation to reduce
borrowings under the utility's credit facility.
Repayments of long-term debt and capital lease obligations and net borrowings
(repayments) under committed credit facilities for the first quarter of 2011
compared to the same quarter of 2010 are summarized in the following tables.
--------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Properties (2) (14) 12
Other (2) (2) -
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Total (4) (16) 12
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--------------------------------------------------------------------------
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
($ millions) 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
FortisAlberta 12 40 (28)
FortisBC Electric - (9) 9
Newfoundland Power 13 11 2
Corporate (10) (71) 61
--------------------------------------------------------------------------
Total 15 (29) 44
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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.
Advances of approximately $17 million were received, during the first quarter of
2011, from non-controlling interests in the Waneta Expansion Limited Partnership
("Waneta Partnership") to finance capital expenditures related to the Waneta
Expansion Project.
In January 2010 Fortis completed a $250 million offering of 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 fund an
equity injection into FEI.
Common share dividends paid were $51 million during the first quarter of 2011,
up $3 million from the same quarter of 2010. The increase was due to a higher
quarterly dividend paid per common share and an increase in the number of common
shares outstanding. The dividend paid per common share for the first quarter of
2011 was $0.29 compared to $0.28 for the first quarter of 2010. The weighted
average number of common shares outstanding during the first quarter of 2011 was
175.0 million, compared to 171.6 million during the first quarter of 2010.
CONTRACTUAL OBLIGATIONS
Consolidated contractual obligations of Fortis over the next five years and for
periods thereafter, as at March 31, 2011, are outlined in the following table. A
detailed description of the nature of the obligations is provided in the MD&A
for the year ended December 31, 2010 and below, where applicable.
--------------------------------------------------------------------------
Contractual Obligations
(Unaudited) Due Due in Due in Due
As at March 31, 2011 within 1 years 2 years 4 after 5
($ millions) Total year and 3 and 5 years
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Long-term debt 5,658 52 389 783 4,434
Brilliant Terminal Station 59 3 5 5 46
Gas purchase contract
obligations (1) 469 218 193 58 -
Power purchase obligations
FortisBC Electric 2,896 44 88 81 2,683
FortisOntario 446 45 97 101 203
Maritime Electric 231 55 83 78 15
Belize Electricity 155 14 34 37 70
Capital cost (2) 443 17 32 34 360
Joint-use asset and share
service agreements 65 4 8 7 46
Office lease - FortisBC
Electric 18 2 3 3 10
Operating lease obligations 120 18 29 27 46
Defined benefit pension
funding contributions (3) 69 27 38 1 3
Other 18 3 7 7 1
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Total 10,647 502 1,006 1,222 7,917
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(1) Based on index prices as at March 31, 2011
(2) Maritime Electric has entitlement to approximately 4.7% of the output
from Point Lepreau for the life of the unit. As part of its
participation agreement, the Company is obligated to pay its share of
capital and operating costs of the unit, which have been included in
the table above. However, as a result of the Accord, the Government of
PEI is assuming responsibility for the payment of the monthly
operating and maintenance costs related to Point Lepreau, effective
March 1, 2011 until Point Lepreau is fully refurbished, which is
expected by fall 2012.
(3) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than these 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 FortisBC Electric
December 31, 2011 Newfoundland Power
December 31, 2012 FortisBC Energy (covering non-unionized
employees)
December 31, 2013 FortisBC Energy (covering unionized employees)
The estimate of defined benefit pension funding contributions above
includes the impact of the outcome of the December 31, 2010 actuarial
valuation, completed during the first quarter of 2011, associated with
the defined benefit pension plan at FortisBC Energy covering unionized
employees, as well as other revised actuarial estimates.
Other contractual obligations, which are not reflected in the above table, did
not change from that disclosed in the MD&A for the year ended December 31, 2010.
For a discussion of the nature and amount of the Corporation's consolidated
capital expenditure program, which is not included in the contractual
obligations table above, refer to the "Capital Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to 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. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt issues. To help ensure access to capital, the Corporation targets
a consolidated long-term capital structure containing approximately 40% equity,
including preference shares, and 60% debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own capital
structure in line with the deemed capital structure reflected in the utilities'
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
--------------------------------------------------------------------------
Capital Structure (Unaudited) As at
March 31, 2011 December 31, 2010
($ millions) (%)($ millions) (%)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,829 57.5 5,914 58.4
Preference shares (2) 912 9.0 912 9.0
Common shareholders' equity 3,397 33.5 3,305 32.6
--------------------------------------------------------------------------
Total (3) 10,138 100.0 10,131 100.0
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(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity
(3) Excludes amounts related to non-controlling interests
--------------------------------------------------------------------------
The change in the capital structure was driven by net earnings applicable to
common shares, net of common share dividends, and lower short-term borrowings,
combined with increased common shares outstanding mainly reflecting the impact
of the Corporation's dividend reinvestment and stock option plans.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
The credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level and the significant
reduction in external debt at FortisBC Holdings Inc., the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis.
CAPITAL PROGRAM
Capital investment in infrastructure is required to ensure continued and
enhanced performance, reliability and safety of the gas and electricity systems
and to meet customer growth. All costs considered to be maintenance and repairs
are expensed as incurred. Costs related to replacements, upgrades and
betterments of capital assets are capitalized as incurred.
A breakdown of the $233 million in gross capital expenditures by segment for the
first quarter of 2011 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Quarter Ended March 31, 2011
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Elec- Regu- Elec-
tric lated tric Non-
FortisBC New- Utili- Utili- Utili- Regu-
Energy Fortis found- ties - ties - ties - lated - Fortis
Com- Alber- FortisBC land Cana- Cana- Cari- Utility Proper-
panies ta (2) Electric Power dian dian bbean (3) ties Total
----------------------------------------------------------------------------
49 85 30 14 8 186 21 23 3 233
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(1)Relates to cash payments to acquire or construct utility capital assets,
income producing properties and intangible assets, as reflected in the
consolidated statement of cash flows. Includes asset removal and site
restoration expenditures, net of salvage proceeds, for those utilities where
such expenditures are permissible in rate base in 2011. Excludes capitalized
amortization and non-cash equity component of the allowance for funds used
during construction.
(2)Includes payments made to the Alberta Electric System Operator for
investment in transmission-related capital projects
(3)Includes non-regulated generation, mainly related to the Waneta Expansion
Project, and corporate capital expenditures
----------------------------------------------------------------------------
There has been no material change in forecast gross consolidated capital
expenditures for 2011 from the approximate $1.2 billion forecast as was
disclosed in the MD&A for the year ended December 31, 2010. Planned capital
expenditures are based on detailed forecasts of energy demand, weather, cost of
labour and materials, as well as other factors, including economic conditions,
which could change and cause actual expenditures to differ from forecasts.
There are no material changes in the overall expected level, nature and timing
of the Corporation's significant capital projects from those disclosed in the
MD&A for the year ended December 31, 2010, except as described below.
In March 2011 Fortis Properties filed a development application to construct a
12-storey office building in St. John's, Newfoundland, subject to municipal
government approval. The $50 million project will feature 145,000 square feet of
Class A office space and include 183 parking spaces and is expected to be
completed in 2013.
Over the five-year period 2011 through 2015, consolidated gross capital
expenditures are expected to be approximately $5.5 billion. Approximately 63% of
the capital spending is expected to be incurred at the regulated electric
utilities, driven by FortisAlberta and FortisBC Electric. Approximately 20% and
17% of the capital spending is expected to be incurred at the regulated gas
utilities and at the non-regulated operations, respectively. Capital
expenditures at the regulated utilities are subject to regulatory approval.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest
costs will generally be paid out of operating cash flows, with varying levels of
residual cash flow available for subsidiary capital expenditures and/or dividend
payments to Fortis. Borrowings under credit facilities may be required from time
to time to support seasonal working capital requirements. Cash required to
complete subsidiary capital expenditure programs is also expected to be financed
from a combination of borrowings under credit facilities, equity injections from
Fortis and long-term debt issues.
The Corporation's ability to service its debt obligations and pay dividends on
its common and preference shares is dependent on the financial results of the
operating subsidiaries and the related cash payments from these subsidiaries.
Certain regulated subsidiaries may be subject to restrictions which may limit
their ability to distribute cash to Fortis. Cash required of Fortis to support
subsidiary capital expenditure programs and finance acquisitions is expected to
be derived from a combination of borrowings under the Corporation's committed
credit facility and proceeds from the issuance of common shares, preference
shares and long-term debt. Depending on the timing of cash payments from the
subsidiaries, borrowings under the Corporation's committed credit facility may
be required from time to time to support the servicing of debt and payment of
dividends.
As at March 31, 2011, management expects consolidated long-term debt maturities
and repayments to average approximately $250 million annually over the next five
years. The combination of available credit facilities and relatively low annual
debt maturities and repayments provide the Corporation and its subsidiaries with
flexibility in the timing of access to capital markets.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009
Rate Application in June 2008, Belize Electricity continues to not meet certain
debt covenant financial ratios related to loans with the International Bank for
Reconstruction and Development and the Caribbean Development Bank totalling $4
million (BZ$8 million) as at March 31, 2011.
As the hydroelectric assets and water rights of the Exploits River Hydro
Partnership ("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 $57 million as at March 31, 2011 (December 31, 2010 - $58
million). The lenders of the term loan have not demanded accelerated repayment.
The scheduled repayments under the term loan are being made by Nalcor, a Crown
corporation, acting as an agent for the Government of Newfoundland and Labrador
with respect to the expropriation matters. For further information refer to Note
30 to the Corporation's 2010 annual audited consolidated financial statements.
Except for the debt at Belize Electricity and the Exploits Partnership, as
discussed above, Fortis and its subsidiaries were in compliance with debt
covenants as at March 31, 2011 and are expected to remain compliant throughout
2011.
CREDIT FACILITIES
As at March 31, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.5 billion was
unused, including $445 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% of these facilities. Approximately $2.0 billion of the total credit
facilities are committed facilities, the majority of which currently have
maturities in 2012, 2013 and 2014.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities (Unaudited) As at
Corporate Regulated Fortis March 31, December
($ millions) and Other Utilities Properties 2011 31, 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit facilities 645 1,440 13 2,098 2,109
Credit facilities
utilized:
Short-term borrowings - (255) (4) (259) (358)
Long-term debt
(including current
portion) (155) (79) - (234) (218)
Letters of credit
outstanding (1) (122) - (123) (124)
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Credit facilities
unused 489 984 9 1,482 1,409
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As at March 31, 2011 and December 31, 2010, 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 2011 Maritime Electric renewed its unsecured committed revolving
credit facility, which matures annually in March. The unsecured committed
revolving credit facility was reduced from $60 million to $50 million.
In April 2011 FortisBC Electric negotiated and finalized an amended credit
facility agreement resulting in an extension to the maturity of the Company's
$150 million unsecured committed revolving credit facility with $100 million now
maturing in May 2014 and $50 million now maturing in May 2012.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows:
--------------------------------------------------------------------------
Financial Instruments (Unaudited) As at
March 31, 2011 December 31, 2010
Estimated Estimated
Carrying Fair Carrying Fair
($ millions) Value Value Value Value
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Waneta Partnership promissory note 43 41 42 40
Long-term debt, including current
portion (1) 5,658 6,278 5,669 6,431
Preference shares, classified as debt
(2) 320 343 320 344
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(1) Carrying value as at March 31, 2011 excludes unamortized deferred
financing costs of $41 million (December 31, 2010 - $42 million) and
capital lease obligations of $39 million (December 31, 2010 - $38
million).
(2) Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was
$612 million as at March 31, 2011 (December 31, 2010 - $615 million).
--------------------------------------------------------------------------
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Partnership promissory note, 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 or promissory note 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.
Risk Management: The Corporation's earnings from, and net investment in,
self-sustaining foreign subsidiaries are exposed to fluctuations in the US
dollar-to-Canadian dollar exchange rate. The Corporation has effectively
decreased the above exposure through the use of US dollar borrowings at the
corporate level. The foreign exchange gain or loss on the translation of US
dollar-denominated interest expense partially offsets the foreign exchange loss
or gain on the translation of the Corporation's foreign subsidiaries' earnings,
which are denominated in US dollars or a currency pegged to the US dollar.
Belize Electricity's reporting currency is the Belizean dollar, while the
reporting currency of Caribbean Utilities, FortisUS Energy Corporation, Belize
Electric Company Limited, and Fortis Turks and Caicos is the US dollar. The
Belizean dollar is pegged to the US dollar at BZ$2.00=US$1.00.
As at March 31, 2011, all of the Corporation's US$590 million (December 31, 2010
- US$590 million) corporately held long-term debt had been designated as a hedge
of a significant portion of the Corporation's foreign net investments. Foreign
currency exchange rate fluctuations associated with the translation of the
Corporation's corporately held US dollar borrowings designated as hedges are
recognized in other comprehensive income and help offset unrealized foreign
currency gains and losses on the foreign net investments, which are also
recognized in other comprehensive income. As at March 31, 2011, 98% of the
Corporation's foreign net investments were hedged (December 31, 2010 - 99%).
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes.
The following table summarizes the valuation of the Corporation's derivative
financial instruments.
--------------------------------------------------------------------------
Derivative Financial Instruments (Unaudited) As at
March 31, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
Term to Number Value Fair Value Value Fair Value
Maturity of Con- ($ milli- ($ milli- ($ milli- ($ milli-
Liability (years) tracts ons) ons) ons) ons)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Foreign
exchange
forward less than
contracts 1.5 2 - - - -
Natural gas
derivatives:
Swaps and
options Up to 4 123 (121) (121) (162) (162)
Gas purchase
contract
premiums Up to 3 30 (2) (2) (5) (5)
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The foreign exchange forward contracts are held by the FortisBC Energy
companies. During 2010 FEI entered into a foreign exchange forward contract to
hedge the cash flow risk related to approximately US$7 million remaining to be
paid under a contract for the implementation of a customer information system.
FEVI also hedges the cash flow risk related to approximately US$1 million
remaining to be paid under a contract for the construction of an LNG storage
facility.
The natural gas derivatives are held by the FortisBC Energy 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 FortisBC Energy companies aims to improve the
likelihood that natural gas prices remain competitive with electricity rates,
temper gas price volatility on customer rates and reduce the risk of regional
price discrepancies.
The changes in the fair values of the foreign exchange forward contracts and
natural gas derivatives are deferred as a regulatory asset or liability, subject
to regulatory approval, for recovery from, or refund to, customers in future
rates. The fair values of the foreign exchange forward contracts and the natural
gas derivatives were recorded in accounts payable as at March 31, 2011 and as at
December 31, 2010.
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 FortisBC Energy
companies would have to receive or pay to terminate the outstanding contracts as
at the balance sheet dates.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $123 million, as at March
31, 2011, 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
There were no changes in the Corporation's significant business risks during the
first quarter of 2011 from those disclosed in the MD&A for the year ended
December 31, 2010, except for those described below.
Capital Resources and Liquidity Risk - Credit Ratings: Fortis and its regulated
utilities do not anticipate any material adverse rating actions by the credit
rating agencies in the near term. During the first quarter of 2011, DBRS
confirmed its existing credit rating for Newfoundland Power.
Defined Benefit Pension Plan Performance: As at March 31, 2011, the fair value
of the Corporation's consolidated defined benefit pension plan assets was $746
million, up $19 million, or 2.6%, from $727 million as at December 31, 2010.
Labour Relations: The collective agreement between FortisBC Electric and Local
378 of the Canadian Office and Professional Employees Union ("COPE") expired
January 31, 2011. The Company and COPE were exploring the amalgamation of
FortisBC Electric and FEI's collective agreements with COPE. The parties have
agreed to terminate discussions and proceed with negotiations to renew the COPE
collective agreement for FortisBC Electric. In the interim, the current
collective agreement remains in full effect until such time as the parties
negotiate and ratify a new agreement.
CHANGE IN ACCOUNTING TREATMENT
Effective January 1, 2011, as approved by the regulator, the cost of OPEB plans
at Newfoundland Power is being expensed and recovered in customer rates based on
the accrual method of accounting for OPEBs. The Company's transitional
regulatory OPEB asset of $53 million as at December 31, 2010 is being amortized
on a straight-line basis over 15 years. During the three months ended March 31,
2011, operating expenses increased by approximately $2 million as a result of
this change in accounting treatment. Prior to January 1, 2011, the cost of OPEB
plans at Newfoundland Power was being expensed and recovered in customer rates
based on the cash payments made.
FUTURE ACCOUNTING CHANGES
Adoption of New Accounting Standards: Due to the continued uncertainty around
the timing and adoption of a rate-regulated accounting standard by the
International Accounting Standards Board, Fortis has evaluated the option of
adopting United States generally accepted accounting principles ("US GAAP"), as
opposed to International Financial Reporting Standards ("IFRS"), effective
January 1, 2012. Canadian rules allow a reporting issuer to prepare and file its
financial statements in accordance with US GAAP by qualifying as a U.S.
Securities and Exchange Commission ("SEC") Issuer. An SEC Issuer is defined
under the Canadian rules as an issuer that: (i) has a class of securities
registered with the SEC under Section 12 of the U.S. Securities Exchange Act of
1934, as amended (the "Exchange Act"); or (ii) is required to file reports under
Section 15(d) of the Exchange Act. The Corporation has developed and initiated a
plan to become an SEC Issuer by December 31, 2011. As an SEC Issuer, Fortis will
then be permitted to prepare and file its consolidated financial statements in
accordance with US GAAP. Barring a change that will provide certainty as to the
Corporation's ability to recognize regulatory assets and liabilities under IFRS,
Fortis expects to prepare its consolidated financial statements in accordance
with US GAAP for all interim and annual periods beginning on or after January 1,
2012. Several other Canadian investor-owned rate-regulated utilities are also
expected to take a similar approach to possible adoption of US GAAP in 2012.
The adoption of US GAAP in 2012 is expected to result in fewer significant
changes to the Corporation's accounting policies as compared to accounting
policy changes that may have resulted from the adoption of IFRS. The
Corporation's application of Canadian GAAP currently relies on US GAAP for
guidance on accounting for rate-regulated activities, which allows the economic
impact of rate-regulated activities to be recognized in the consolidated
financial statements in a manner consistent with the timing by which amounts are
reflected in customer rates. Fortis believes that the continued application of
rate-regulated accounting, and the associated recognition of regulatory assets
and liabilities under US GAAP, more accurately reflects the impact that rate
regulation has on the Corporation's consolidated financial position and results
of operations. Should the Corporation not be successful in becoming an SEC
Issuer by December 31, 2011, Fortis will be required to adopt IFRS effective
January 1, 2012.
The Corporation has developed a three-phase plan to adopt US GAAP effective
January 1, 2012. The following is an overview of the activities under each phase
and their current status.
Phase I - Scoping and Diagnostics: This phase consists of project initiation and
awareness; project planning and resourcing; identification of high-level
differences between US GAAP and Canadian GAAP to highlight areas where detailed
analysis is needed to determine and conclude as to the nature and extent of
impacts; and identification of SEC registration procedures and subsequent
reporting requirements. External accounting and legal advisors were engaged
during this phase to assist the Corporation's internal US GAAP conversion team
and to provide technical input and expertise as required. Phase I commenced in
the fourth quarter of 2010 and is now substantially complete. All remaining
Phase I activities are scheduled for completion by mid-2011.
Phase II - Analysis and Development: This phase consists of detailed diagnostics
and evaluation of the financial impacts of adopting US GAAP based on the
high-level assessment conducted under Phase I; the registration of securities as
required to achieve SEC Issuer status; identification and design of any new
operational or financial business processes; and development of required
solutions to address identified issues. Phase II also includes an assessment of
ongoing requirements of the US Sarbanes-Oxley Act ("SOX"), including auditor
attestation of internal controls over financial reporting, and a comparison of
the requirements under SOX to those required in Canada under National Instrument
52-109 Certification of Disclosure in Issuers' Annual and Interim Filings.
Phase II of the plan commenced in January 2011. Based on the research and
analysis completed to date, and the Corporation's continued ability to apply
rate-regulated accounting policies under US GAAP, the differences between US
GAAP and Canadian GAAP are not expected to have a material impact on
consolidated earnings and are expected to be mostly limited to changes in
balance sheet classifications and additional disclosure requirements. The impact
on information systems is also expected to be minimal.
Phase II, including the quantification of differences between US GAAP and
Canadian GAAP and reconciliation of the Corporation's financial statements from
Canadian GAAP to US GAAP for 2009 and 2010, is scheduled for completion by
September 30, 2011.
Phase III - Implementation and Review: This phase involves implementation of the
changes required by the Corporation to prepare and file its consolidated
financial statements based on US GAAP beginning in 2012 and communication of the
associated impacts. Phase III will commence in the second quarter of 2011.
Beginning with the first quarter of 2012, the Corporation's unaudited interim
consolidated financial statements are expected to be prepared in accordance with
US GAAP. Phase III will essentially conclude when the Corporation issues its
first annual audited US GAAP consolidated financial statements for the year
ending December 31, 2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial
statements in accordance with Canadian GAAP requires management to make
estimates and judgments that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the consolidated financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are based on
historical experience, current conditions and various other assumptions believed
to be reasonable under the circumstances. Additionally, certain estimates and
judgments are necessary since the regulatory environments in which the
Corporation's utilities operate often require amounts to be recorded at
estimated values until these amounts are finalized pursuant to regulatory
decisions or other regulatory proceedings. Due to changes in facts and
circumstances and the inherent uncertainty involved in making estimates, actual
results may differ significantly from current estimates. Estimates and judgments
are reviewed periodically and, as adjustments become necessary, are reported in
earnings in the period they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the first quarter of 2011
from those disclosed in the MD&A for the year ended December 31, 2010.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with ordinary course business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations. There were no material changes in the
Corporation's contingent liabilities from those disclosed in the MD&A for the
year ended December 31, 2010.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended June 30, 2009 through March 31, 2011. 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, 3 and 5 to the Corporation's 2010 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.
--------------------------------------------------------------------------
Net Earnings
Attributable
Summary of to Common
Quarterly Results Equity
(Unaudited) Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic($) Diluted ($)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
March 31, 2011 1,164 117 0.67 0.65
December 31, 2010 1,036 85 0.49 0.47
September 30, 2010 720 45 0.26 0.26
June 30, 2010 835 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
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 cost of natural gas, which
are flowed through to customers without markup. Given the diversified nature of
the Fortis subsidiaries, seasonality may vary. Most of the annual earnings of
the FortisBC Energy companies are realized in the first and fourth quarters.
Financial results for the fourth quarter ended December 31, 2009 reflected the
favourable cumulative retroactive impact, from January 1, 2009, associated with
an increase in the allowed ROE and equity component for FortisAlberta. The
commissioning of the Vaca hydroelectric generating facility in March 2010 has
favourably impacted financial results since that date. Financial results 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 October 2009 have been
favourably impacted by the acquisition of Algoma Power.
March 2011/March 2010: Net earnings attributable to common equity shareholders
were $117 million, or $0.67 per common share, for the first quarter of 2011
compared to earnings of $100 million, or $0.58 per common share, for the first
quarter of 2010. A discussion of the variances between the financial results for
the first quarter of 2011 and the first quarter of 2010 is provided in the
"Financial Highlights" section of this MD&A.
December 2010/December 2009: Net earnings attributable to common equity
shareholders were $85 million, or $0.49 per common share, for the fourth quarter
of 2010 compared to earnings of $81 million, or $0.48 per common share, for the
fourth quarter of 2009. The increase was mainly due to improved performance at
Canadian Regulated Electric Utilities, non-regulated hydroelectric generation
operations in Belize and lower effective corporate income taxes at Fortis
Properties, partially offset by lower earnings from the FortisBC Energy
companies and Caribbean Regulated Electric Utilities. Improved performance at
Canadian Regulated Electric Utilities was driven by overall growth in electrical
infrastructure investment, combined with customer growth at FortisAlberta and
the higher allowed ROE at FortisBC Electric. Earnings were lower quarter over
quarter at the FortisBC Energy companies, as a result of higher
regulator-approved operating expenses and the timing of the recognition of these
increased expenses, and at Caribbean Regulated Electric Utilities, mainly due to
lower electricity sales associated with cooler-than-normal temperatures
experienced in the region and the inability of Belize Electricity to earn a fair
and reasonable return due to regulatory challenges. Earnings for the fourth
quarter of 2009 were reduced by $5 million related to the expensing of the
project cost overrun associated with the conversion Whistler customer appliances
from propane to natural gas, but were favourably impacted by a one-time $3
million tax adjustment at FortisOntario.
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 FortisBC Energy companies and higher corporate expenses.
Improved performance at the regulated electric utilities in western Canada was
due to higher allowed ROEs and/or equity component of capital structure, 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 Electric 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 at the FortisBC Energy companies quarter over quarter largely
related to increased operating and maintenance expenses at FEI 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 FortisBC Energy
companies and FortisBC Electric, partially offset by higher corporate expenses.
The increase in earnings at the FortisBC Energy companies related to higher
allowed ROEs and equity component of capital structure. The improvement in
earnings at FortisBC Electric 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 business development costs incurred in 2010 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 of
capital structure, 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.
OUTLOOK
The Corporation's significant capital program, which is expected to be $5.5
billion over the next five years, 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 May 3, 2011, the Corporation had issued and outstanding 175.5 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 May 3, 2011 is as follows:
-------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at May 3, 2011
Number of Common
Security Shares (millions)
-------------------------------------------------------------------
-------------------------------------------------------------------
Stock Options 5.0
Convertible Debt 1.4
First Preference Shares, Series C 4.1
First Preference Shares, Series E 6.5
-------------------------------------------------------------------
Total 17.0
-------------------------------------------------------------------
-------------------------------------------------------------------
Additional information, including the Fortis 2010 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three months ended March 31, 2011 and 2010
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31, December 31,
2011 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 86 $ 109
Accounts receivable (Note 18) 700 655
Prepaid expenses 18 17
Regulatory assets (Note 5) 201 241
Inventories (Note 6) 88 168
Future income taxes 16 14
--------------------------
1,109 1,204
Assets held for sale 45 45
Other assets 166 168
Regulatory assets (Note 5) 866 831
Future income taxes 10 16
Utility capital assets 8,351 8,202
Income producing properties 556 560
Intangible assets 325 324
Goodwill 1,549 1,553
--------------------------
$ 12,977 $ 12,903
--------------------------------------------------------------------------
--------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 18) $ 259 $ 358
Accounts payable and accrued charges 942 953
Dividends payable 55 54
Income taxes payable 42 30
Regulatory liabilities (Note 5) 89 60
Current installments of long-term debt and
capital lease obligations (Note 7) 55 56
Future income taxes 3 6
--------------------------
1,445 1,517
Other liabilities 309 308
Regulatory liabilities (Note 5) 509 467
Future income taxes 629 623
Long-term debt and capital lease obligations
(Note 7) 5,601 5,609
Preference shares 320 320
--------------------------
8,813 8,844
--------------------------
Shareholders' equity
Common shares (Note 8) 2,607 2,578
Preference shares 592 592
Contributed surplus 12 12
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (Note 10) (97) (94)
Retained earnings 870 804
--------------------------
3,989 3,897
Non-controlling interests 175 162
--------------------------
4,164 4,059
--------------------------
$ 12,977 $ 12,903
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Contingent liabilities and commitments (Note 19)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended
2011 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue $ 1,164 $ 1,073
------------------------
Expenses
Energy supply costs 603 552
Operating 213 202
Amortization 103 94
------------------------
919 848
------------------------
Operating income 245 225
Finance charges (Note 12) 90 90
------------------------
Earnings before corporate taxes 155 135
Corporate taxes (Note 13) 30 28
------------------------
Net earnings $ 125 $ 107
------------------------
Net earnings attributable to:
Non-controlling interests $ 1 $ 1
Preference equity shareholders 7 6
Common equity shareholders 117 100
------------------------
$ 125 $ 107
------------------------
Earnings per common share (Note 8)
Basic $ 0.67 $ 0.58
Diluted $ 0.65 $ 0.56
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2011 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Balance at beginning of period $ 804 $ 763
Net earnings attributable to common and
preference equity shareholders 124 106
--------------------------
928 869
Dividends on common shares (51) (96)
Dividends on preference shares classified as
equity (7) (6)
--------------------------
Balance at end of period $ 870 $ 767
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2011 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Net earnings $ 125 $ 107
------------------------------
Other comprehensive (loss) income
Unrealized foreign currency translation
losses on net investments in self-
sustaining foreign operations (15) (20)
Gains on hedges of net investments in self-
sustaining foreign operations 14 14
Corporate tax expense (2) (2)
------------------------------
Unrealized foreign currency translation
losses, net of hedging activities and
tax(Note 10) (3) (8)
------------------------------
Comprehensive income $ 122 $ 99
------------------------------
Comprehensive income attributable to:
Non-controlling interests $ 1 $ 1
Preference equity shareholders 7 6
Common equity shareholders 114 92
------------------------------
$ 122 $ 99
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2011 2010
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(Note 20)
Operating activities
Net earnings $125 $107
Items not affecting cash:
Amortization - utility capital assets
and income producing properties 94 83
Amortization - intangible assets 10 11
Amortization - other (1) -
Future income taxes (2) (3)
Other (2) 2
Change in long-term regulatory assets
and liabilities 18 4
--------------------------------
242 204
Change in non-cash operating working
capital 57 (3)
--------------------------------
299 201
--------------------------------
Investing activities
Change in other assets and other
liabilities (3) 2
Capital expenditures - utility capital
assets (219) (179)
Capital expenditures - income producing
properties (3) (6)
Capital expenditures - intangible assets (11) (3)
Contributions in aid of construction 12 10
Proceeds on sale of utility capital
assets and income producing properties 5 -
--------------------------------
(219) (176)
--------------------------------
Financing activities
Change in short-term borrowings (98) (181)
Repayments of long-term debt and capital
lease obligations (4) (16)
Net borrowings (repayments) under
committed credit facilities 15 (29)
Advances from non-controlling interests 17 -
Issue of common shares, net of costs 27 23
Issue of preference shares, net of costs - 242
Dividends
Common shares (51) (48)
Preference shares (7) (6)
Subsidiary dividends paid to non-
controlling interests (2) (2)
--------------------------------
(103) (17)
--------------------------------
Effect of exchange rate changes on cash
and cash equivalents - (1)
--------------------------------
Change in cash and cash equivalents (23) 7
Cash and cash equivalents, beginning of
period 109 85
--------------------------------------------------------------------------
Cash and cash equivalents, end of period $86 $92
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
15)
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2011 and 2010
(unless otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international
distribution utility holding company. Fortis segments its utility operations by
franchise area and, depending on regulatory requirements, by the nature of the
assets. Fortis also holds investments in non-regulated generation assets, and
commercial office and retail space and hotels, which are treated as two separate
segments. The Corporation's reporting segments allow senior management to
evaluate the operational performance and assess the overall contribution of each
segment to the long-term objectives of Fortis. Each 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 2010
annual audited consolidated financial statements.
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities in Canada
and the Caribbean by utility are as follows:
a. Regulated Gas Utilities - Canadian: Includes the FortisBC Energy
companies, which is comprised of FortisBC Energy Inc. ("FEI") (formerly
Terasen Gas Inc.), FortisBC Energy (Vancouver Island) Inc. ("FEVI")
(formerly Terasen Gas (Vancouver Island) Inc.) and FortisBC Energy
(Whistler) Inc. (formerly Terasen Gas (Whistler) Inc.).
b. Regulated Electric Utilities - Canadian: Includes FortisAlberta;
FortisBC Electric (formerly referred to as 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 Algoma Power Inc.
c. Regulated Electric Utilities - Caribbean: Includes Belize Electricity,
in which Fortis holds an approximate 70% controlling ownership interest;
Caribbean Utilities, in which Fortis holds an approximate 59%
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 2.7 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 FortisBC Holdings Inc. ("FHI") (formerly Terasen Inc.)
corporate-related activities, and the financial results of FHI's 30% ownership
interest in CustomerWorks Limited Partnership and of FHI's non-regulated wholly
owned subsidiary FortisBC Alternative Energy Services Inc. (formerly 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 2010 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, most of the earnings of the FortisBC Energy companies are
realized 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 2010 annual audited consolidated
financial statements, except as described below.
Effective January 1, 2011, as approved by the regulator, the cost of other
post-employment benefit ("OPEB") plans at Newfoundland Power is being expensed
and recovered in customer rates based on the accrual method of accounting for
OPEBs. The Company's transitional regulatory OPEB asset of $53 million as at
December 31, 2010 is being amortized on a straight-line basis over 15 years.
During the three months ended March 31, 2011, operating expenses increased by
approximately $2 million as a result of this change in accounting treatment.
Prior to January 1, 2011, the cost of OPEB plans at Newfoundland Power was being
expensed and recovered in customer rates based on the cash payments made.
3. FUTURE ACCOUNTING CHANGES
Effective January 1, 2012, the Corporation will be required to adopt a new set
of accounting standards. Publicly accountable enterprises in Canada were
required to adopt International Financial Reporting Standards ("IFRS") effective
January 1, 2011; however, qualifying entities with rate-regulated activities
were granted an optional one-year deferral for the adoption of IFRS, due to the
continued uncertainty around the timing and adoption of a rate-regulated
accounting standard by the International Accounting Standards Board ("IASB"). As
a qualifying entity with rate-regulated activities, Fortis has elected to opt
for the one-year deferral and, therefore, will continue to prepare its
consolidated financial statements in accordance with Part V of the Canadian
Institute of Chartered Accountants Handbook for all interim and annual periods
ending on or before December 31, 2011.
Due to the continued uncertainty around the timing and adoption of a
rate-regulated accounting standard by the IASB, Fortis has evaluated the option
of adopting United States generally accepted accounting principles ("US GAAP"),
as opposed to IFRS, effective January 1, 2012. Canadian rules allow a reporting
issuer to prepare and file its financial statements in accordance with US GAAP
by qualifying as a U.S. Securities and Exchange Commission ("SEC") Issuer. An
SEC Issuer is defined under the Canadian rules as an issuer that: (i) has a
class of securities registered with the SEC under Section 12 of the U.S.
Securities Exchange Act of 1934, as amended (the "Exchange Act"); or (ii) is
required to file reports under Section 15(d) of the Exchange Act. The
Corporation has developed and initiated a plan to become an SEC Issuer by
December 31, 2011. As an SEC Issuer, Fortis will then be permitted to prepare
and file its consolidated financial statements in accordance with US GAAP.
Barring a change that will provide certainty as to the Corporation's ability to
recognize regulatory assets and liabilities under IFRS, Fortis expects to
prepare its consolidated financial statements in accordance with US GAAP for all
interim and annual periods beginning on or after January 1, 2012.
The adoption of US GAAP in 2012 is expected to result in fewer significant
changes to the Corporation's accounting policies as compared to accounting
policy changes that may have resulted from the adoption of IFRS. The
Corporation's application of Canadian GAAP currently relies on US GAAP for
guidance on accounting for rate-regulated activities, which allows the economic
impact of rate-regulated activities to be recognized in the consolidated
financial statements in a manner consistent with the timing by which amounts are
reflected in customer rates. Fortis believes that the continued application of
rate-regulated accounting, and the associated recognition of regulatory assets
and liabilities under US GAAP, more accurately reflects the impact that rate
regulation has on the Corporation's consolidated financial position and results
of operations. Should the Corporation not be successful in becoming an SEC
Issuer by December 31, 2011, Fortis will be required to adopt IFRS effective
January 1, 2012.
4. USE OF ESTIMATES
The preparation of 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 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 in which they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the three months ended March
31, 2011.
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 5 to the Corporation's 2010 annual
audited consolidated financial statements.
As at
March 31, December 31,
($ millions) 2011 2010
--------------------------------------------------------------------------
Regulatory assets
Future income taxes 583 568
Rate stabilization accounts - FortisBC Energy
companies 112 146
Rate stabilization accounts - electric utilities 49 44
Regulatory OPEB plan assets 66 66
Point Lepreau (1) replacement energy deferral 47 44
2010 accrued distribution revenue adjustment
rider 27 36
Deferred energy management costs 24 23
Deferred losses on disposal of utility capital
assets 19 16
Income taxes recoverable on OPEB plans 18 18
Alberta Electric System Operator ("AESO")
charges deferral 17 19
Deferred operating costs 14 11
Deferred development costs for capital 11 11
Deferred costs - smart meters 8 8
Deferred lease costs 6 6
Deferred pension costs 5 5
Other regulatory assets 61 51
--------------------------------------------------------------------------
Total regulatory assets 1,067 1,072
Less: current portion (201) (241)
--------------------------------------------------------------------------
Long-term regulatory assets 866 831
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
March 31, December 31,
($ millions) 2011 2010
--------------------------------------------------------------------------
Regulatory liabilities
Asset removal and site restoration provision 343 339
Rate stabilization accounts - FortisBC Energy
companies 119 60
Rate stabilization accounts - electric utilities 50 45
AESO charges deferral 12 9
Deferred interest 8 7
Performance-based rate-setting incentive
liabilities 7 8
Southern Crossing Pipeline deferral 7 5
Unrecognized net gains on disposal of utility
capital assets 6 8
Unbilled revenue liability 6 5
2010 FEI revenue surplus 5 7
Other regulatory liabilities 35 34
--------------------------------------------------------------------------
Total regulatory liabilities 598 527
Less: current portion (89) (60)
--------------------------------------------------------------------------
Long-term regulatory liabilities 509 467
--------------------------------------------------------------------------
--------------------------------------------------------------------------
6. INVENTORIES
As at
March 31, December 31,
($ millions) 2011 2010
--------------------------------------------------------------------------
Gas in storage 65 148
Materials and supplies 23 20
--------------------------------------------------------------------------
88 168
--------------------------------------------------------------------------
--------------------------------------------------------------------------
During the three months ended March 31, 2011, inventories of $344 million were
expensed and reported in energy supply costs on the interim consolidated
statement of earnings ($305 million for the three months ended March 31, 2010).
Inventories expensed to operating expenses were $3 million for the three months
ended March 31, 2011 ($3 million for the three months ended March 31, 2010),
which included $2 million for food and beverage costs at Fortis Properties ($2
million for the three months ended March 31, 2010).
7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at
March 31, December 31,
($ millions) 2011 2010
--------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,463 5,489
Long-term classification of committed credit
facilities (Note 18) 234 218
Deferred debt financing costs (41) (42)
--------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,656 5,665
Less: Current installments of long-term debt and
capital
lease obligations (55) (56)
--------------------------------------------------------------------------
5,601 5,609
--------------------------------------------------------------------------
--------------------------------------------------------------------------
8. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value.
As at
Issued and Outstanding March 31, 2011 December 31, 2010
Number of Number of
Shares Shares
(in Amount (in Amount
thousands) ($ millions) thousands) ($ millions)
--------------------------------------------------------------------------
Common shares 175,422 2,607 174,393 2,578
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended
March 31, 2011
Number of
Shares Amount
(in thousands) ($ millions)
--------------------------------------------------------------------------
Balance, beginning of period 174,393 2,578
Dividend Reinvestment Plan 515 17
Consumer Share Purchase Plan 13 1
Stock Option Plans 501 11
--------------------------------------------------------------------------
Balance, end of period 175,422 2,607
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Earnings per Common Share
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding.
Diluted EPS was calculated using the treasury stock method for options and the
"if-converted" method for convertible securities.
EPS were as follows:
Quarter Ended March 31
2011 2010
--------------------------------------------------------
Weighted Weighted
Average Average
Earnings Shares Earnings Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
--------------------------------------------------------------------------
Basic EPS 117 175.0 $0.67 100 171.6 $0.58
Effect of
potential
dilutive
securities:
Stock Options - 1.2 - 1.0
Preference
Shares (Note
12) 4 10.1 4 11.9
Convertible
Debentures 1 1.4 1 1.4
--------------------------------------------------------------------------
Diluted EPS 122 187.7 $0.65 105 185.9 $0.56
--------------------------------------------------------------------------
--------------------------------------------------------------------------
9. STOCK-BASED COMPENSATION PLANS
In January 2011 27,070 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 ("DSU") represents a unit with an underlying value
equivalent to the value of one common share of the Corporation. In March 2011
31,821 DSUs were paid out as a result of the death of one of the members of the
Board of Directors of Fortis at $33.06 per DSU, for a total of approximately
$1.1 million.
In March 2011 45,000 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 2011 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 March 2011 37,079 PSUs
were paid out to the President and CEO of the Corporation at $33.11 per PSU, for
a total of approximately $1.2 million. The payout was made upon the three-year
maturation period in respect of the PSU grant made in February 2008 and the
President and CEO satisfying the payment requirements, as determined by the
Human Resources Committee of the Board of Directors.
In March 2011 the Corporation granted 828,512 options to purchase common shares
under its 2006 Stock Option Plan at the five-day volume weighted average trading
price of $32.95 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 $4.57 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.68
Expected volatility (%) 23.1
Risk-free interest rate (%) 2.00
Weighted average expected life (years) 4.5
As at March 31, 2011, 5.0 million stock options were outstanding and 2.7 million
stock options were vested.
10. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, and gains and losses on
discontinued cash flow hedging activities as described in Note 3 to the
Corporation's 2010 annual audited consolidated financial statements.
Quarter Ended March 31
2011 2010
----------------------------------------------------------
Opening Ending Opening Ending
balance Net balance balance Net balance
($ millions) January 1 change March 31 January 1 change March 31
--------------------------------------------------------------------------
Unrealized
foreign
currency
translation
losses, net of
hedging
activities and
tax (90) (3) (93) (78) (8) (86)
Net losses on
derivative
instruments
previously
discontinued as
cash flow
hedges, net of
tax (4) - (4) (5) - (5)
--------------------------------------------------------------------------
Accumulated
other
comprehensive
loss (94) (3) (97) (83) (8) (91)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
11. 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 $15 million for the three
months ended March 31, 2011 ($9 million for the three months ended March 31,
2010). The cost of providing the defined contribution arrangements and group
RRSPs for the three months ended March 31, 2011 was $4 million ($4 million for
the three months ended March 31, 2010).
12. FINANCE CHARGES
Quarter Ended
March 31
($ millions) 2011 2010
--------------------------------------------------------------------
Interest - Long-term debt and
capital lease
obligations 90 88
- Short-term borrowings
and other 4 2
Interest charged during
construction (8) (4)
Dividends on preference
shares classified as
debt (Note 8) 4 4
--------------------------------------------------------------------
90 90
--------------------------------------------------------------------
--------------------------------------------------------------------
13. 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
March 31
($ millions, except as noted) 2011 2010
--------------------------------------------------------------------------
Combined Canadian federal and provincial
statutory income tax rate 30.5 % 32.0 %
--------------------------------------------------------------------------
Statutory income tax rate applied to earnings
before corporate taxes 47 43
Preference share dividends 1 1
Difference between Canadian statutory rate and
rates applicable to
foreign subsidiaries (2) (2)
Difference in Canadian provincial statutory
rates applicable to
subsidiaries in different Canadian
jurisdictions (6) (4)
Items capitalized for accounting purposes but
expensed for income
tax purposes (16) (12)
Difference between capital cost allowance and
amounts claimed for
accounting purposes 3 -
Other 3 2
--------------------------------------------------------------------------
Corporate taxes 30 28
--------------------------------------------------------------------------
Effective tax rate 19.4 % 20.7 %
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at March 31, 2011, the Corporation had approximately $97 million (December
31, 2010 - $101 million) in non-capital and capital loss carryforwards, of which
$18 million (December 31, 2010 - $18 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2014 and 2031.
14. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
FortisBC
Quarter Ended Energy
March 31, Companies New- Other Total Electric
2011 - Fortis FortisBC foundland Cana- Electric Carib-
($ millions) Canadian Alberta Electric Power dian Canadian bean
----------------------------------------------------------------------------
Revenue 575 103 83 183 91 460 76
Energy supply
costs 344 - 23 134 60 217 46
Operating
expenses 77 35 18 20 12 85 11
Amortization 26 33 11 10 6 60 9
----------------------------------------------------------------------------
Operating
income 128 35 31 19 13 98 10
Finance
charges 29 13 9 9 5 36 5
Corporate tax
expense
(recovery) 23 1 3 3 2 9 -
----------------------------------------------------------------------------
Net earnings
(loss) 76 21 19 7 6 53 5
Non-
controlling
interests - - - - - - 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to
common equity
shareholders 76 21 19 7 6 53 4
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 130
Identifiable
assets 4,250 2,181 1,285 1,223 647 5,336 774
----------------------------------------------------------------------------
Total assets 5,158 2,408 1,506 1,223 710 5,847 904
----------------------------------------------------------------------------
Gross capital
expenditures
(2) 49 85 30 14 8 137 21
----------------------------------------------------------------------------
Quarter Ended
March 31,
2010
($ millions)
----------------------------------------------------------------------------
Revenue 526 87 72 178 82 419 76
Energy supply
costs 305 - 21 131 53 205 45
Operating
expenses 70 35 17 16 11 79 12
Amortization 27 24 10 11 5 50 9
----------------------------------------------------------------------------
Operating
income 124 28 24 20 13 85 10
Finance
charges 27 14 8 9 6 37 5
Corporate tax
expense
(recovery) 24 - 2 4 2 8 -
----------------------------------------------------------------------------
Net earnings
(loss) 73 14 14 7 5 40 5
Non-
controlling
interests - - - - - - 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to
common equity
shareholders 73 14 14 7 5 40 4
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 136
Identifiable
assets 4,130 1,922 1,157 1,208 620 4,907 781
----------------------------------------------------------------------------
Total assets 5,038 2,149 1,378 1,208 683 5,418 917
----------------------------------------------------------------------------
Gross capital
expenditures
(2) 50 64 26 17 8 115 17
----------------------------------------------------------------------------
(1) Results reflect contribution from the Vaca hydroelectric generating
facility in Belize, which was commissioned in March 2010, and the Waneta
Partnership, which was established in October 2010.
(2)Relates to cash payments to acquire or construct utility capital assets,
including amounts for AESO transmision-related capital projects, income
producing properties and intangible assets, as reflected on the
consolidated statement of cash flows
NON-REGULATED
------------------------------------
Quarter Ended
March 31, Fortis Inter-
2011 Gene- Fortis Corporate segment
($ millions) ration(1) Properties and Other eliminations Consolidated
--------------------------------------------------------------------------
Revenue 7 50 7 (11) 1,164
Energy supply
costs - - - (4) 603
Operating
expenses 3 37 2 (2) 213
Amortization 1 5 2 - 103
--------------------------------------------------------------------------
Operating
income 3 8 3 (5) 245
Finance
charges - 6 19 (5) 90
Corporate tax
expense
(recovery) - 1 (3) - 30
--------------------------------------------------------------------------
Net earnings
(loss) 3 1 (13) - 125
Non-
controlling
interests - - - - 1
Preference
share
dividends - - 7 - 7
--------------------------------------------------------------------------
Net earnings
(loss)
attributable
to
common equity
shareholders 3 1 (20) - 117
--------------------------------------------------------------------------
Goodwill - - - - 1,549
Identifiable
assets 402 575 483 (392) 11,428
--------------------------------------------------------------------------
Total assets 402 575 483 (392) 12,977
--------------------------------------------------------------------------
Gross capital
expenditures
(2) 23 3 - - 233
--------------------------------------------------------------------------
Quarter Ended
March 31,
2010
($ millions)
--------------------------------------------------------------------------
Revenue 5 49 7 (9) 1,073
Energy supply
costs - - - (3) 552
Operating
expenses 2 36 4 (1) 202
Amortization 1 4 3 - 94
--------------------------------------------------------------------------
Operating
income 2 9 - (5) 225
Finance
charges - 6 20 (5) 90
Corporate tax
expense
(recovery) - 1 (5) - 28
--------------------------------------------------------------------------
Net earnings
(loss) 2 2 (15) - 107
Non-
controlling
interests - - - - 1
Preference
share
dividends - - 6 - 6
--------------------------------------------------------------------------
Net earnings
(loss)
attributable
to
common equity
shareholders 2 2 (21) - 100
--------------------------------------------------------------------------
Goodwill - - - - 1,555
Identifiable
assets 183 607 518 (421) 10,705
--------------------------------------------------------------------------
Total assets 183 607 518 (421) 12,260
--------------------------------------------------------------------------
Gross capital
expenditures
(2) 1 5 - - 188
--------------------------------------------------------------------------
(1) Results reflect contribution from the Vaca hydroelectric generating
facility in Belize, which was commissioned in March 2010, and the Waneta
Partnership, which was established in October 2010.
(2)Relates to cash payments to acquire or construct utility capital
assets, including amounts for AESO transmision-related capital projects,
income producing properties and intangible assets, as reflected on the
consolidated statement of cash flows
Inter-segment transactions are in the normal course of operations and are
measured at the exchange amount, which is the amount of consideration
established and agreed to by the related parties. The significant inter-segment
transactions primarily related to the sale of energy from Fortis Generation to
Belize Electricity, electricity sales from Newfoundland Power to Fortis
Properties and finance charges on inter-segment borrowings. The significant
inter-segment transactions for the three months ended March 31, 2011 and 2010
were as follows:
Significant Inter-Segment Transactions Quarter Ended
March 31
($ millions) 2011 2010
--------------------------------------------------------------------------
Sales from Fortis Generation to Regulated Electric
Utilities - Caribbean 4 3
Sales from Newfoundland Power to Fortis Properties 1 1
Inter-segment finance charges on borrowings from:
Corporate to Regulated Electric Utilities -
Caribbean 1 1
Corporate to Fortis Generation 1 1
Corporate to Fortis Properties 3 2
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at March 31
($ millions) 2011 2010
--------------------------------------------------------------------------
Inter-segment borrowings from:
Corporate to Regulated Electric Utilities -
Canadian 50 75
Corporate to Regulated Electric Utilities -
Caribbean 58 46
Corporate to Fortis Generation 50 58
Corporate to Fortis Properties 222 223
Other inter-segment assets 12 19
--------------------------------------------------------------------------
Total inter-segment eliminations 392 421
--------------------------------------------------------------------------
--------------------------------------------------------------------------
15. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended
March 31
($ millions) 2011 2010
--------------------------------------------------------------------------
Interest paid 81 81
Income taxes paid 24 24
--------------------------------------------------------------------------
--------------------------------------------------------------------------
16. 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 at
the corporate level with proceeds from common share, preference share and
long-term debt issues. To help ensure access to capital, the Corporation targets
a consolidated long-term capital structure containing approximately 40% equity,
including preference shares, and 60% debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own capital
structure in line with the deemed capital structure reflected in the utilities'
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
As at
March 31, 2011 December 31, 2010
($ ($
millions) (%) millions) (%)
--------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,829 57.5 5,914 58.4
Preference shares (2) 912 9.0 912 9.0
Common shareholders' equity 3,397 33.5 3,305 32.6
--------------------------------------------------------------------------
Total (3) 10,138 100.0 10,131 100.0
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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% of the Corporation's consolidated capital structure, as defined by
the long-term debt agreements. In addition, one of the Corporation's long-term
debt obligations contains a covenant which provides that Fortis shall not
declare or pay any dividends, other than stock dividends or cumulative preferred
dividends on preference shares not issued as stock dividends, or make any other
distribution on its shares or redeem any of its shares or prepay subordinated
debt if, immediately thereafter, its consolidated funded obligations would be in
excess of 75% of its total consolidated capitalization.
As at March 31, 2011, the Corporation and its subsidiaries, except for certain
debt at Belize Electricity and the Exploits River Hydro Partnership ("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 continues to not meet certain
debt covenant financial ratios related to loans with the International Bank for
Reconstruction and Development and the Caribbean Development Bank totalling $4
million (BZ$8 million) as at March 31, 2011.
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 $57 million as at March 31,
2011 (December 31, 2010 - $58 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan are
being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to expropriation matters.
For further information refer to Note 30 to the Corporation's 2010 annual
audited consolidated financial statements.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 18.
17. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the three months ended March 31, 2011 in the
designation of the Corporation's financial instruments from that disclosed in
the Corporation's 2010 annual audited consolidated financial statements.
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows:
As at
March 31, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Waneta Partnership
promissory note (1) (2) 43 41 42 40
Long-term debt, including
current portion (3) (4) 5,658 6,278 5,669 6,431
Preference shares,
classified as debt (3)
(5) 320 343 320 344
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Included in other liabilities on the consolidated balance sheet
(2) Carrying value is a discounted present value.
(3) Carrying value is measured at amortized cost using the effective
interest rate method.
(4) Carrying value as at March 31, 2011 excludes unamortized deferred
financing costs of $41 million (December 31, 2010 - $42 million) and
capital lease obligations of $39 million (December 31, 2010 - $38
million).
(5) Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $592 million preference shares classified as equity was $612
million as at March 31, 2011 (December 31, 2010 - $615 million).
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Partnership promissory note, the fair value is determined by discounting
the future cash flows of the specific debt instrument at an estimated yield to
maturity equivalent to benchmark government bonds or treasury bills, with
similar terms to maturity, plus a market credit risk premium equal to that of
issuers of similar credit quality. Since the Corporation does not intend to
settle the long-term debt or promissory note prior to maturity, the fair value
estimate does not represent an actual liability and, therefore, does not include
exchange or settlement costs. The fair value of the Corporation's preference
shares is determined using quoted market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and natural gas prices
through the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes. The following table summarizes the valuation of the Corporation's
consolidated derivative financial instruments.
As at
March 31, 2011 December, 31, 2010
Estimated Estimated
Carrying Fair Carrying Fair
Term to Value Value Value Value
Maturity Number of ($ milli- ($ milli- ($ milli- ($ milli-
Liability (years) Contracts ons) ons) ons) ons)
-----------------------------------------------------------------------------
Foreign
exchange
forward
contracts less than
(1) (2) 1.5 2 - - - -
Natural gas
derivatives
: (1) (3)
Swaps and
options Up to 4 123 (121) (121) (162) (162)
Gas purchase
contract
premiums Up to 3 30 (2) (2) (5) (5)
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
(1)The fair value measurements are Level 2, based on the three levels that
distinguish the level of pricing observability utilized in measuring fair
value.
(2) The fair values of the foreign exchange forward contracts were recorded
in accounts payable as at March 31, 2011 and as at December 31, 2010.
(3) The fair values of the natural gas derivatives were recorded in accounts
payable as at March 31, 2011 and as at December 31, 2010.
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.
18. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit risk Risk that a 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
long-term receivables, 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, prepayments and/or credit
checks for certain customers and performing disconnections and/or using
third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution
service billings being to a relatively small group of retailers. As at March 31,
2011, its gross credit risk exposure was approximately $125 million,
representing the projected value of retailer billings over a 60-day period. The
Company has reduced its exposure to approximately $5 million by obtaining from
the retailers either a cash deposit, bond, letter of credit or an
investment-grade credit rating from a major rating agency, or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The FortisBC Energy companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments. To help
mitigate credit risk, the FortisBC Energy companies deal with high
credit-quality institutions in accordance with established credit-approval
practices. The counterparties with which the FortisBC Energy companies have
significant transactions are A-rated entities or better. The FortisBC Energy
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 $18 million as at March
31, 2011 (December 31, 2010 - $16 million; March 31, 2010 - $17 million) was as
follows:
($ millions) As at
March 31, December 31, March 31,
2011 2010 2010
--------------------------------------------------------------------------
Not past due 601 584 518
Past due 0-30 days 76 56 63
Past due 31-60 days 15 9 14
Past due 61 days and over 8 6 9
--------------------------------------------------------------------------
700 655 604
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at March 31, 2011, other long-term receivables of $14 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 $9 million due after 5 years.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if
it, or one of its subsidiaries, fails to arrange sufficient and cost-effective
financing to fund, among other things, capital expenditures and the repayment of
maturing debt. The ability to arrange sufficient and cost-effective financing is
subject to numerous factors, including the consolidated results of operations
and financial position of the Corporation and its subsidiaries, conditions in
capital and bank credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing
of acquisitions and for general corporate purposes. Depending on the timing of
cash payments from the subsidiaries, borrowings under the Corporation's
committed credit facility may be required from time to time to support the
servicing of debt and payment of dividends. As at March 31, 2011, average annual
consolidated long-term debt maturities and repayments over the next five years
are expected to be approximately $250 million. The combination of available
credit facilities and relatively low annual debt maturities and repayments will
provide the Corporation and its subsidiaries with flexibility in the timing of
access to capital markets.
As at March 31, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.5 billion was
unused. The credit facilities are syndicated almost entirely with the seven
largest Canadian banks, with no one bank holding more than 25% of these
facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
December
Corporate Regulated Fortis March 31, 31,
($ millions) and Other Utilities Properties 2011 2010
--------------------------------------------------------------------------
Total credit
facilities 645 1,440 13 2,098 2,109
Credit facilities
utilized:
Short-term
borrowings - (255) (4) (259) (358)
Long-term debt
(Note 7) (1) (155) (79) - (234) (218)
Letters of credit
outstanding (1) (122) - (123) (124)
--------------------------------------------------------------------------
Credit facilities
unused 489 984 9 1,482 1,409
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) As at March 31, 2011, credit facility borrowings classified as long-
term included $16 million (December 31, 2010 - $16 million) that was
included in current installments of long-term debt and capital lease
obligations on the consolidated balance sheet.
As at March 31, 2011 and December 31, 2010, 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 2011 Maritime Electric renewed its unsecured committed revolving
credit facility, which matures annually in March. The unsecured committed
revolving credit facility was reduced from $60 million to $50 million.
In April 2011 FortisBC Electric negotiated and finalized an amended credit
facility agreement resulting in an extension to the maturity of the Company's
$150 million unsecured committed revolving credit facility with $100 million now
maturing in May 2014 and $50 million now maturing in May 2012.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
March 31, 2011, the Corporation's credit ratings were as follows:
Standard & Poor's A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
The credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level and the significant
reduction in external debt at FHI, the Corporation's reasonable credit metrics
and its demonstrated ability and continued focus on acquiring and integrating
stable regulated utility businesses financed on a conservative basis.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at March 31, 2011.
Due Due in Due in
Financial Liabilities within 1 years years Due after
($ millions) year 2 and 3 4 and 5 5 years Total
--------------------------------------------------------------------------
Short-term borrowings 259 - - - 259
Trade and other accounts
payable 819 - - - 819
Natural gas derivatives
(1) 71 38 8 - 117
Foreign exchange forward
contracts (2) 6 1 - - 7
Dividends payable 55 - - - 55
Customer deposits (3) - 3 1 2 6
Waneta Partnership
promissory note (4) - - - 72 72
Long-term debt,
including current
portion (5) 52 389 783 4,434 5,658
Interest obligations on
long-term debt 346 678 609 4,984 6,617
Preference shares,
classified as debt - 123 - 197 320
Dividend obligations on
preference shares,
classified as finance
charges 17 30 19 5 71
--------------------------------------------------------------------------
1,625 1,262 1,420 9,694 14,001
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at March 31, 2011 at $123
million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts payable at fair value as at March 31, 2011 at less
than $1 million.
(3) Customer deposits were recorded in other liabilities as at March 31,
2011.
(4) Amounts disclosed are on a gross cash flow basis.The promissory note
was recorded in other liabilities at present value as at March 31, 2011 at
$43 million.
(5) Excludes deferred financing costs of $41 million and capital lease
obligations of $39 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 March 31, 2011, all of the Corporation's US$590 million (December 31, 2010
- US$590 million) corporately held long-term debt had been designated as a hedge
of a significant portion of the Corporation's foreign net investments. As at
March 31, 2011, the Corporation had approximately US$14 million (December 31,
2010 - US$7 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
recognized in other comprehensive income and help offset unrealized foreign
currency exchange gains and losses on the foreign net investments, which are
also recognized in other comprehensive income.
FEI and FEVI'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. FEI and FEVI 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.
The FortisBC Energy companies and FortisBC Electric 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 FortisBC Energy 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 natural gas derivatives are recognized on the consolidated
balance sheet at fair value and any change in the fair value is deferred as a
regulatory asset or liability, subject to regulatory approval, for recovery
from, or refund to, customers in future rates.
The price risk-management strategy of the FortisBC Energy companies aims to
improve the likelihood that natural gas prices remain competitive with
electricity rates, temper gas price volatility on customer rates and reduce the
risk of regional price discrepancies. On an annual basis, FEI and FEVI each file
a Price Risk-Management Plan ("PRMP") that seeks approval for the natural gas
commodity hedging plan for the next three years for FEI and the next five years
for FEVI. During the third quarter of 2010, the BCUC denied the PRMP application
filed by the FortisBC Energy companies earlier in 2010 and directed the
Companies to undertake a review of the primary objectives of the PRMP. In
January 2011 the FortisBC Energy companies reviewed the PRMP objectives with the
BCUC related to their gas commodity hedging plan and FEI submitted a 2011-2014
PRMP. On a partial basis, the BCUC has approved FEI to implement portions of its
2011-2014 PRMP. FEVI plans to file an updated PRMP by June 2011.
19. 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 2010 annual audited
consolidated financial statements.
Commitments
There were no material changes in the nature and amount of the Corporation's
commitments from the commitments disclosed in the Corporation's 2010 annual
audited consolidated financial statements, except as described below.
During the first quarter of 2011, the actuarial valuation of the defined benefit
pension plan at FortisBC Energy, covering unionized employees, was completed. As
a result of the actuarial valuation and other revised actuarial estimates, the
total estimate of consolidated defined benefit pension funding contributions
over the next five years has increased approximately $37 million from that
disclosed in the Corporation's 2010 annual audited consolidated financial
statements.
20. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
classifications. The most significant changes related to a $48 million decrease
in cash from operating activities associated with changes in non-cash operating
working capital and a corresponding decrease in cash used in financing
activities associated with dividends on common shares.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with
total assets of approximately $13 billion and fiscal 2010 revenue totalling
approximately $3.7 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 hotels and commercial office and retail space primarily in Atlantic Canada.
The Common Shares, First Preference Shares, Series C; First Preference Shares,
Series E; First Preference Shares, Series F; First Preference Shares, Series G;
and First Preference Shares, Series H of Fortis are traded on the Toronto Stock
Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and
FTS.PR.H, respectively.
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 2010 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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