Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved third quarter net
earnings attributable to common equity shareholders of $58 million, or $0.31 per
common share, compared to $45 million, or $0.26 per common share, for the third
quarter of 2010. Year-to-date net earnings attributable to common equity
shareholders were $233 million, or $1.30 per common share, up $33 million from
earnings of $200 million, or $1.16 per common share, for the same period last
year.
Results for the quarter reflected the $11 million after-tax, or $0.06 per common
share, fee paid to Fortis in July 2011, following upon the termination of the
Merger Agreement between Fortis and Central Vermont Public Service Corporation
announced on May 30, 2011.
Canadian Regulated Gas Utilities incurred a loss of $3 million compared to a
loss of $5 million for the third quarter of 2010. The third quarter is normally
a period of lower customer demand due to warmer temperatures. Results improved
mainly due to the favourable impact during the third quarter of this year of the
timing of operating expenses, which was partially offset by the impact during
the third quarter last year of the $4 million after-tax reversal of previously
expensed project overrun costs related to the conversion of Whistler customer
appliances from propane to natural gas.
Canadian Regulated Electric Utilities contributed earnings of $43 million,
comparable to the third quarter of 2010. Increased earnings from Other Regulated
Electric Utilities, mainly due to a higher allowed rate of return on common
equity at Algoma Power in 2011, were offset by lower earnings from FortisBC
Electric as a result of higher effective corporate income taxes and lower
capitalized allowance for funds used during construction.
In September 2011 Newfoundland Power received regulatory approval for the sale
of 40% of the utility's joint-use poles to Bell Aliant Inc. Proceeds of
approximately $46 million from the pole sale were received in October.
Caribbean Regulated Electric Utilities contributed $6 million to earnings
compared to $8 million for the third quarter of 2010. There was no earnings
contribution from Belize Electricity during the third quarter of 2011 due to the
expropriation by the Government of Belize ("GOB") in June 2011 of the
Corporation's investment in the utility. Earnings contribution from Belize
Electricity during the third quarter last year was approximately $2 million.
Fortis has commissioned an independent valuation of its previous investment in
Belize Electricity and expects to submit its claim for compensation to the GOB
during the fourth quarter of 2011.
Electricity sales at Caribbean Utilities and Fortis Turks and Caicos continue to
be impacted by a decline in customer energy consumption resulting from
persistent challenging economic conditions in the region, high fuel prices and a
declining population. The use of new, more-efficient generating units at Fortis
Turks and Caicos has helped to reduce fuel supply costs at the utility during
2011, thereby mitigating the impact of reduced electricity sales.
Non-Regulated Fortis Generation contributed $8 million to earnings compared to
$9 million for the third quarter of 2010. The decline in earnings reflected
decreased production in Belize due to lower rainfall associated with a longer
dry season in 2011.
Fortis Properties delivered earnings of $9 million, comparable to the third
quarter of 2010. In October 2011 Fortis Properties acquired the 160-room,
full-service Hilton Suites Winnipeg Airport hotel for $25 million.
Corporate and other expenses were $5 million, $14 million lower than the third
quarter of 2010. Excluding the $11 million after-tax termination fee paid to
Fortis in July 2011, corporate and other expenses were $3 million lower, driven
by a favourable foreign exchange gain recognized during the third quarter of
2011.
Cash flow from operating activities was $678 million year to date, up $144
million from $534 million for the same period last year, driven by higher
earnings and favourable working capital changes.
Year-to-date 2011, more than $0.5 billion of long-term capital has been raised
by Fortis and its subsidiaries. In June and July 2011, Fortis issued
approximately 10.3 million common shares for $341 million, the proceeds of which
were used to repay borrowings under credit facilities and finance equity
injections into the regulated utilities in western Canada and the non-regulated
Waneta Expansion Limited Partnership, in support of infrastructure investment,
and for general corporate purposes. In October 2011 FortisAlberta issued 30-year
$125 million 4.54% unsecured debentures and, mid-2011, Caribbean Utilities
issued US$40 million of unsecured notes for terms ranging from 15 to 20 years
and at rates ranging from 4.85% to 5.10%. The proceeds of the debt offerings
were used to repay borrowings under credit facilities incurred to finance
capital expenditures, to finance future capital spending and for general
corporate purposes.
During the third quarter, Fortis renegotiated and amended its committed
corporate credit facility, increasing the amount available under the facility to
$800 million from $600 million and extending the facility's maturity date to
2015 from 2012. FortisAlberta also increased its committed credit facility to
$250 million from $200 million and extended the maturity date of the facility to
2015. DBRS also confirmed the Corporation's debt credit rating at A(low).
"We are focused on completing our $1.2 billion 2011 capital expenditure program,
with planning well underway for a comparable capital program in 2012," says Stan
Marshall, President and Chief Executive Officer, Fortis Inc. "Our five-year
capital expenditure program to the end of 2015 is forecasted to be $5.7 billion.
This investment should drive growth in earnings and dividends," he explains.
"We remain disciplined and patient in our pursuit of electric and gas utility
acquisitions in the United States and Canada that will add value for Fortis
shareholders," concludes Marshall.
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2011
Dated November 3, 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 and
nine months ended September 30, 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; consolidated forecast gross capital expenditures for 2011 and in total
over the five-year period 2011 through 2015; the expectation of little-to-no
growth in electricity sales for Caribbean Utilities and Fortis Turks and Caicos
during 2012 and 2013; the expectation that the Corporation's significant capital
expenditure 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 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; 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 events; the expectation that the Corporation will receive compensation
from the Government of Belize ("GOB") for the fair value of the Corporation's
investment in Belize Electricity that was expropriated by the GOB; the
expectation that Belize Electric Company Limited ("BECOL") will not be
expropriated by the GOB; 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; 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 consolidated
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; risk associated with the amount of compensation to be paid to Fortis for
its investment in Belize Electricity that was expropriated by the GOB; the
timeliness of the receipt of the compensation and the ability of the GOB to pay
the compensation owing to Fortis; risk that the GOB may expropriate BECOL;
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;
changes in tax legislation; information technology infrastructure; an ultimate
resolution of the expropriation of the assets of the Exploits Partnership that
differs from what is currently expected by management; an unexpected outcome of
legal proceedings currently against the Corporation; relations with First
Nations; labour relations; and human resources. For additional information with
respect to the Corporation's risk factors, reference should be made to the
Corporation's continuous disclosure materials filed from time to time with
Canadian securities regulatory authorities and to the heading "Business Risk
Management" in the MD&A for the three and nine months ended September 30, 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
more than 2,000,000 gas and electricity customers. Its regulated holdings
include electric utilities in five Canadian provinces and two 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 in Canada. Year-to-date September 30, 2011, the Corporation's electricity
distribution systems met a combined peak demand of approximately 5,031 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 and nine months ended September 30, 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/or 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 regulator-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 and/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 base customer rates and/or the use of rate stabilization
and other mechanisms.
Effective March 1, 2011, the Terasen Gas companies were renamed to operate 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"), and
collectively are referred to as the FortisBC Energy companies.
On June 20, 2011, the Government of Belize ("GOB") enacted legislation leading
to the expropriation of the Corporation's investment in Belize Electricity. As a
result of no longer controlling the operations of the utility, the Corporation
has discontinued the consolidation method of accounting for Belize Electricity,
effective June 20, 2011, and has classified the book value of the previous
investment in the utility as a long-term other asset on the consolidated balance
sheet of Fortis. As at September 30, 2011, the long-term other asset, including
foreign exchange impacts, totalled $120 million.
Fortis has commissioned an independent valuation of its previous investment in
Belize Electricity and expects to submit its claim to the GOB for compensation
during the fourth quarter of 2011. On October 21, 2011, Fortis commenced an
action in the Belize Supreme Court to challenge the legality of the
expropriation of its investment in Belize Electricity.
Fortis continues to control and consolidate the financial statements of Belize
Electric Company Limited ("BECOL"), the Corporation's indirect wholly owned
non-regulated hydroelectric generation subsidiary in Belize. BECOL generates
hydroelectricity from three plants with a combined generating capacity of 51 MW
located on the Macal River. The entire output of the plants is sold to Belize
Electricity under 50-year contracts expiring in 2055 and 2060. Assuming normal
hydrological conditions, Belize Electricity purchases BECOL's normalized annual
energy production of 240 gigawatt hours ("GWh") at approximately US$0.10 per
kilowatt hour, which generally is the lowest-cost energy supply source in the
country of Belize. As at September 30, 2011, the book value of the Corporation's
investment in BECOL was $159 million. In 2009 the GOB purported to designate
BECOL and other independent power producers in Belize as public utility
providers. On October 25, 2011, the GOB amended the Constitution of Belize to
require majority government ownership of three public utility providers,
including Belize Electricity, but excluding BECOL. The Prime Minister of Belize
has stated that the GOB has neither the intention nor the resources to
expropriate BECOL.
As at October 31, 2011, Belize Electricity owed BECOL US$8 million for overdue
energy purchases representing about one-third of BECOL's annual sales to Belize
Electricity. In accordance with long-standing agreements, the GOB guarantees the
payment of Belize Electricity's obligations to BECOL.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the third quarter and
year-to-date periods ended September 30, 2011 and September 30, 2010 are
provided in the following table.
----------------------------------------------------------------------------
Consolidated Financial Highlights (Unaudited)
Periods Ended September
30 Quarter Year-to-Date
($ millions, except for
common share data) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
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Revenue 721 720 1 2,735 2,627 108
Energy Supply Costs 246 259 (13) 1,207 1,178 29
Operating Expenses 202 196 6 627 600 27
Amortization 105 117 (12) 311 307 4
Finance Charges 88 88 - 271 266 5
Corporate Taxes 12 5 7 57 48 9
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Net Earnings 68 55 13 262 228 34
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Net Earnings
Attributable to:
Non-Controlling
Interests 3 3 - 7 7 -
Preference Equity
Shareholders 7 7 - 22 21 1
Common Equity
Shareholders 58 45 13 233 200 33
----------------------------------------------------------------------------
Net Earnings 68 55 13 262 228 34
----------------------------------------------------------------------------
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Basic Earnings per
Common Share ($) 0.31 0.26 0.05 1.30 1.16 0.14
Diluted Earnings per
Common Share ($) 0.31 0.26 0.05 1.29 1.15 0.14
Weighted Average Number
of Common Shares
Outstanding (#
millions) 186.5 173.2 13.3 179.5 172.4 7.1
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Cash Flow from Operating
Activities 151 129 22 678 534 144
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Factors Contributing to Quarterly Revenue Variance
Favourable
-- The $17 million (US$17.5 million) fee paid to Fortis in July 2011,
following upon the termination of a Merger Agreement between Fortis and
Central Vermont Public Service Corporation ("CVPS")
-- Growth in the number of customers mainly at FortisAlberta
-- An increase in gas delivery rates and the base component of electricity
rates at several of the regulated utilities, consistent with rate
decisions, reflecting ongoing investment in utility infrastructure,
higher regulator-approved expenses recoverable from customers, and a
higher allowed ROE at Algoma Power
-- The flow through in customer electricity rates of overall higher energy
supply costs, driven by Caribbean Utilities
-- Higher hospitality revenue at Fortis Properties
Unfavourable
-- The timing of recording of the favourable cumulative impact of
FortisAlberta's 2010 revenue requirements decision. The impact of the
rate decision was recorded during the third quarter of 2010 when the
decision was received.
-- Lower commodity cost of natural gas charged to customers
-- Lower gas sales
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Increased performance-based rate-setting ("PBR") incentive adjustments
owing to customers by FortisBC Electric
-- Approximately $5 million unfavourable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar period over
period
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The same factors as discussed above for the quarter
-- Overall higher electricity sales
-- Higher gas sales
-- The recognition of $3 million of accrued revenue at FortisAlberta year-
to-date 2011 related primarily to the cumulative 2010 and year-to-date
2011 allowed return and recovery of amortization on the additional $22
million in capital expenditures associated with the Automated Metering
Project, as approved by the regulator to be included in rate base
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Increased PBR incentive adjustments, as discussed above for the quarter
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Approximately $15 million associated with unfavourable foreign currency
translation
Factors Contributing to Quarterly Energy Supply Costs Variance
Favourable
-- Lower commodity cost of natural gas
-- Lower gas sales
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Approximately $3 million associated with favourable foreign currency
translation
Unfavourable
-- Increased fuel costs at Caribbean Utilities
Factors Contributing to Year-to-Date Energy Supply Costs Variance
Unfavourable
-- Overall higher gas and electricity sales
-- Increased fuel costs at Caribbean Utilities
Favourable
-- Lower commodity cost of natural gas
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Lower-than-expected purchased power costs at FortisBC Electric
-- Approximately $9 million associated with favourable foreign currency
translation
Factors Contributing to Quarterly Operating Expenses Variance
Unfavourable
-- Higher operating expenses at Newfoundland Power, mainly due to the
regulator-approved change in the accounting treatment for other post-
employment benefit ("OPEB") costs
-- Wage and general inflationary cost increases
-- The regulator-approved reversal in the third quarter of 2010 of $5
million ($4 million after tax) of previously expensed project overrun
costs related to the conversion of Whistler customer appliances from
propane to natural gas
Favourable
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Operating costs of approximately $2 million incurred during the third
quarter of 2010 at Newfoundland Power as a result of Hurricane Igor
-- Lower-than-expected operating expenses for the third quarter of 2011 at
the FortisBC Energy companies, due to the timing of spending and
capitalization of certain operating expenses during 2011
-- Approximately $1 million associated with favourable foreign currency
translation
Factors Contributing to Year-to-Date Operating Expenses Variance
Unfavourable
-- The same factors as discussed above for the quarter
-- Higher operating expenses year to date at the FortisBC Energy companies,
due to the timing of spending of certain regulator-approved increased
operating expenses during 2011
Favourable
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Operating costs of approximately $2 million incurred during the third
quarter of 2010 at Newfoundland Power as a result of Hurricane Igor
-- Higher corporate operating expenses incurred in the first half of 2010
related to business development costs
-- Approximately $2 million associated with favourable foreign currency
translation
Factors Contributing to Quarterly Amortization Costs Variance
Favourable
-- Lower amortization costs at FortisAlberta, due to the timing of
recording of the cumulative impact of FortisAlberta's 2010 revenue
requirements decision. The impact of the rate decision was recorded
during the third quarter of 2010 when the decision was received.
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Approximately $0.5 million associated with favourable foreign currency
translation
Unfavourable
-- Continued investment in utility infrastructure and income producing
properties, combined with the commissioning of the liquefied natural gas
("LNG") storage facility during the second quarter of 2011
Factors Contributing to Year-to-Date Amortization Costs Variance
Unfavourable
-- The same factor as discussed above for the quarter
Favourable
-- Reduced amortization costs in 2011 at the FortisBC Energy companies,
mainly due to the retirement late in 2010 of certain general plant
assets and the amortization in 2011 of a regulatory deferral account
-- Regulator-approved increased amortization costs at Newfoundland Power
year-to-date 2010, due to approximately $3 million of adjustments
related to an amortization study
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Approximately $2 million associated with favourable foreign currency
translation
Factors Contributing to Quarterly and Year-to-Date Finance Charges Variances
Favourable
-- A net foreign exchange gain associated with the previously hedged
investment in Belize Electricity
-- The refinancing of maturing corporate debt at lower rates
-- Higher capitalized allowance for funds used during construction
("AFUDC") year to date, mainly at the FortisBC Energy companies and
FortisAlberta
Unfavourable
-- Higher debt levels in support of the utilities' capital expenditure
programs
-- Lower capitalized AFUDC for the quarter, mainly at FortisBC Electric
Factors Contributing to Quarterly and Year-to-Date Corporate Taxes Variances
Unfavourable
-- Higher proportion of consolidated income earned in taxable jurisdictions
-- Lower deductions for income tax purposes compared to accounting purposes
Favourable
-- Lower statutory income tax rates
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- The $11 million after-tax fee paid to Fortis in July 2011, following
upon the termination of the Merger Agreement between Fortis and CVPS
-- An approximate $6 million and $17 million earnings impact for the
quarter and year to date, respectively, related to rate base growth,
mainly at the regulated utilities in western Canada, due to continued
investment in utility infrastructure
-- A net foreign exchange gain of approximately $2.5 million after tax,
associated with the previously hedged investment in Belize Electricity
-- Higher corporate operating expenses incurred in the first half of 2010
related to business development costs
-- The cumulative allowed return and recovery of amortization of
approximately $1.5 million, relating to 2010, on the additional capital
expenditures at FortisAlberta included in rate base associated with the
Automated Metering Project, as discussed above, as recorded in the
second quarter of 2011
-- Overall higher electricity sales year to date, and growth in the number
of customers at FortisAlberta
-- Higher capitalized AFUDC year to date, mainly at the FortisBC Energy
companies and FortisAlberta
-- Lower-than-expected operating costs for the third quarter of 2011 at the
FortisBC Energy companies, due to the timing of spending and
capitalization of certain operating expenses during 2011
-- Lower-than-expected purchased power costs at FortisBC Electric year to
date
-- A higher allowed ROE at Algoma Power
Unfavourable
-- The regulator-approved reversal in the third quarter of 2010 of $4
million after tax of previously expensed project overrun costs related
to the conversion of Whistler customer appliances from propane to
natural gas
-- Higher operating expenses at the FortisBC Energy companies year-to-date
2011, due to the timing of spending of certain regulator-approved
increased operating expenses during 2011
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011. There was no earnings contribution
from Belize Electricity year-to-date 2011, while the company contributed
approximately $2 million in earnings for each of the third quarter and
year-to-date period in 2010.
-- Decreased earnings from non-regulated hydroelectric generation
operations, mainly reflecting decreased production at BECOL due to lower
rainfall
-- Lower capitalized AFUDC for the quarter, mainly at FortisBC Electric
-- The timing of recording the 2010 revenue requirements decision at
FortisAlberta. The favourable cumulative impact of the decision was
recorded during the third quarter of 2010 when the decision was
received.
-- Approximately $1 million for the quarter and $1.5 million year to date
associated with unfavourable foreign currency translation
SEGMENTED RESULTS OF OPERATIONS
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy Companies (3) (5) 2 88 85 3
----------------------------------------------------------------------------
Regulated Electric Utilities
-Canadian
FortisAlberta 19 19 - 59 51 8
FortisBC Electric 10 11 (1) 38 33 5
Newfoundland Power 8 8 - 26 26 -
Other Canadian Electric
Utilities 6 5 1 18 14 4
----------------------------------------------------------------------------
43 43 - 141 124 17
----------------------------------------------------------------------------
Regulated Electric Utilities -
Caribbean 6 8 (2) 16 19 (3)
Non-Regulated - Fortis
Generation 8 9 (1) 13 14 (1)
Non-Regulated - Fortis
Properties 9 9 - 18 19 (1)
Corporate and Other (5) (19) 14 (43) (61) 18
----------------------------------------------------------------------------
Net Earnings Attributable to
Common Equity Shareholders 58 45 13 233 200 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended September
30 Quarter Year-to-Date
(TJ) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Core - Residential and
Commercial 10,560 12,342 (1,782) 85,959 76,600 9,359
Industrial 820 840 (20) 3,937 3,708 229
----------------------------------------------------------------------------
Total Sales Volumes 11,380 13,182 (1,802) 89,896 80,308 9,588
Transportation Volumes 11,858 11,458 400 49,072 41,958 7,114
Throughput under Fixed
Revenue Contracts 69 3,592 (3,523) 1,034 10,358 (9,324)
----------------------------------------------------------------------------
Total Gas Volumes 23,307 28,232 (4,925) 140,002 132,624 7,378
----------------------------------------------------------------------------
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(1) The FortisBC Energy companies are comprised of FEI, FEVI and FEWI.
Factors Contributing to Quarterly Gas Volumes Variances
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 for significant
periods during 2011
-- Lower average consumption by residential and commercial customers as a
result of warmer weather
Favourable
-- Higher transportation volumes reflecting improving economic conditions
favourably affecting the forestry and mining sectors and some mining
customers burning more natural gas due to a shortage of coal
Factors Contributing to Year-to-Date Gas Volumes Variances
Favourable
-- Higher average consumption by residential and commercial customers as a
result of cooler weather for the first half of 2011
-- Higher transportation volumes, for the same reasons as discussed above
for the quarter
Unfavourable
-- Lower volumes under fixed revenue contracts, for the same reason as
discussed above for the quarter
Customer additions were 1,965 year-to-date 2011 compared to 3,460 during the
same period in 2010. Customer additions decreased due to lower building activity
during 2011.
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 residential and commercial customer gas
rates do not materially affect earnings.
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.
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 198 206 (8) 1,093 1,067 26
(Loss) earnings (3) (5) 2 88 85 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Lower average gas consumption by residential and commercial customers,
partially offset by higher transportation volumes to forestry and mining
customers
Favourable
-- An increase in the delivery component of customer rates, mainly due to
ongoing investment in utility infrastructure and higher regulator-
approved operating expenses recoverable from customers
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The same factor as discussed above for the quarter
-- Higher average gas consumption by residential and commercial customers
-- Higher transportation volumes to forestry and mining customers
Unfavourable
-- Lower commodity cost of natural gas charged to customers
Factors Contributing to Quarterly Loss Variance
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
-- Lower-than-expected operating expenses for the third quarter of 2011,
due to the timing of spending and capitalization of certain operating
expenses during 2011
-- Lower effective corporate income taxes reflecting a lower statutory
income tax rate
Unfavourable
-- The regulator-approved reversal in the third quarter of 2010 of $4
million after tax of previously expensed project overrun costs related
to the conversion of Whistler customer appliances from propane to
natural gas
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
-- Lower-than-expected amortization costs, mainly due to the retirement
late in 2010 of certain general plant assets
-- Higher transportation volumes to forestry and mining customers
-- Higher capitalized AFUDC
-- Lower effective corporate income taxes reflecting a lower statutory
income tax rate
Unfavourable
-- Higher operating expenses, due to the timing of spending of regulator-
approved increased operating expenses during 2011, driven by labour and
benefits costs and consulting expenses related to feasibility studies
-- The regulator-approved reversal in the third quarter of 2010 of $4
million after tax of previously expensed project overrun costs related
to the conversion of Whistler customer appliances from propane to
natural gas
-- Higher finance charges associated with credit facility borrowings
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (GWh) 3,911 3,778 133 12,135 11,611 524
Revenue ($ millions) 103 109 (6) 310 289 21
Earnings ($ millions) 19 19 - 59 51 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Energy Deliveries Variance
Favourable
-- Higher average consumption by commercial and farm and irrigation
customers, due to differences in temperature and rainfall period over
period
-- Growth in the number of customers, mainly residential and commercial,
with the total number of customers increasing by approximately 8,800
quarter over quarter
Unfavourable
-- Lower average consumption by residential customers, due to warmer-than-
average temperatures, which decreased home-heating load
Factors Contributing to Year-to-Date Energy Deliveries Variance
Favourable
-- The same factors as discussed above for the quarter
-- Higher average consumption by residential customers due to cooler-than-
average temperatures during the first quarter of 2011, which increased
home-heating load
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 Quarterly Revenue Variance
Unfavourable
-- The favourable cumulative impact of the 2010 revenue requirements
decision was recorded during the third quarter of 2010 when the decision
was received. Approximately $14 million of the total revenue accrued in
the third quarter of 2010, as a result of the rate decision, related to
the first half of 2010. Most of the rate revenue accrual related to
regulator-approved increased amortization, operating costs and interest
expense.
Favourable
-- A 4.7% increase in base customer electricity distribution rates over
2010 rates, effective January 1, 2011. The increase in base rates was
primarily due to ongoing investment in utility infrastructure.
-- Growth in the number of customers
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The 4.7% increase in base customer electricity distribution rates, as
discussed above for the quarter
-- The recognition of $3 million of accrued revenue year-to-date 2011
related primarily to the cumulative allowed return and recovery of
amortization on the additional capital expenditures approved by the
regulator to be included in rate base associated with the Automated
Metering Project. Approximately $1.5 million of the accrual related to
2010. For further information, refer to the "Material Regulatory
Decisions and Applications - FortisAlberta" section of this MD&A.
-- Growth in the number of customers
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
-- Higher-than-expected customer growth and energy deliveries
Unfavourable
-- The timing of recording the 2010 revenue requirements decision. The
favourable cumulative impact of the decision was recorded during the
third quarter of 2010 when the decision was received.
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
-- The cumulative allowed return and recovery of amortization of
approximately $1.5 million, relating to 2010, on the additional capital
expenditures associated with the Automated Metering Project, as
discussed above
-- A $1 million gain on the sale of property during the first quarter of
2011
-- Higher capitalized AFUDC
In August 2011 FortisAlberta filed a short-form prospectus which contemplates
the issuance of up to $500 million senior unsecured debentures over the 25-month
period through to September 2013. For further information, refer to the
"Subsequent Events" section of this MD&A.
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 713 709 4 2,300 2,199 101
Revenue ($ millions) 67 62 5 215 193 22
Earnings ($ millions) 10 11 (1) 38 33 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Quarterly and Year-to-Date Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Lower average consumption during the first quarter of 2010, due to
warmer-than-average temperatures experienced during that period,
resulting in higher electricity sales year to date
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- A 6.6% increase in customer electricity rates, effective January 1,
2011, mainly reflecting ongoing investment in utility infrastructure
-- A refundable interim 1.4% and a 2.9% increase in customer electricity
rates, effective June 1, 2011 and September 1, 2010, respectively, as a
result of the flow through to customers of increased purchased power
costs charged to FortisBC Electric by BC Hydro
-- The 0.6% and 4.6% increase in electricity sales for the quarter and year
to date, respectively
-- Higher revenue contribution from non-regulated operating, maintenance
and management services
-- Higher wheeling revenue year to date
Unfavourable
-- Higher-than-expected PBR incentive adjustments owing to customers
-- Lower surplus electricity sales
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Lower capitalized AFUDC, due to fewer assets under construction during
2011
-- Higher effective corporate income taxes, mainly due to lower deductions
for income tax purposes compared to accounting purposes
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Rate base growth, for the same reason as discussed above for the quarter
-- Lower-than-expected energy supply costs primarily due to lower average
market-priced purchased power costs, partially offset by the related
incentive owing back to customers
-- Lower-than-expected average consumption in the first quarter of 2010,
for the same reason discussed above
Unfavourable
-- The same factors as discussed above for the quarter
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 923 916 7 4,026 3,931 95
Revenue ($ millions) 101 99 2 417 403 14
Earnings ($ millions) 8 8 - 26 26 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption year to date reflecting the higher
concentration of electric versus oil heating in new homes combined with
strong economic growth
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 0.8% and 2.4% increase in electricity sales for the quarter and year
to date, respectively
-- 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
Unfavourable
-- Decreased amortization of regulatory liabilities and deferrals, as
approved by the regulator
-- Lower joint-use pole-related revenue, due to new support structure
arrangements with Bell Aliant Inc. ("Bell Aliant"), effective January 1,
2011. For further information, refer to the "Material Regulatory
Decisions and Applications - Newfoundland Power" and "Subsequent Events"
sections of this MD&A.
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- Electricity sales growth
-- Lower effective corporate income taxes, primarily due to a lower
statutory income tax rate
-- Operating expenses during the third quarter of 2010 included
approximately $2 million in additional operating labour and maintenance
costs as a result of Hurricane Igor in September 2010
Unfavourable
-- The decrease in the allowed ROE, as reflected in customer rates
-- Wage and general inflationary cost increases
-- Higher employee-related operating expenses
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 582 583 (1) 1,798 1,750 48
Revenue ($ millions) 88 87 1 256 244 12
Earnings ($ millions) 6 5 1 18 14 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
-- Growth in the number of residential customers
-- Higher average consumption, reflecting colder temperatures in Ontario
and on Prince Edward Island ("PEI") during the first half of 2011
compared to the same period of 2010, which increased home-heating load,
resulting in increased electricity sales year to date
Unfavourable
-- Lower average consumption by industrial customers on PEI due to a
reduction in farm crop storage and warehousing activities
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 2.7% increase in electricity sales year to date
-- An increase in the basic component of customer rates at Maritime
Electric associated with the recovery of energy supply costs
-- 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
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario for the quarter
Unfavourable
-- Lower load demand revenue for the quarter from commercial customers on
PEI
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- A higher allowed ROE at Algoma Power and the use of a forward test year
for rate setting, as reflected in customer rates for 2011
-- Electricity sales growth year to date
-- Lower effective corporate income taxes at FortisOntario, primarily due
to higher deductions taken for income tax purposes compared to
accounting purposes
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange
Rate (2) 0.98 1.04 (0.06) 0.98 1.04 (0.06)
Electricity Sales (GWh) 197 318 (121) 744 880 (136)
Revenue ($ millions) 73 92 (19) 236 251 (15)
Earnings ($ millions) 6 8 (2) 16 19 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which
Fortis holds an approximate 59% controlling interest; wholly owned
Fortis Turks and Caicos; and the financial results of the Corporation's
approximate 70% controlling interest in Belize Electricity up to June
20, 2011. Effective June 20, 2011, the GOB enacted legislation leading
to the expropriation of the Corporation's investment in Belize
Electricity. As a result of no longer controlling the operations of the
utility, Fortis discontinued the consolidation method of accounting for
Belize Electricity, effective June 20, 2011. For further information,
refer to the "Corporate Overview" and "Business Risk Management -
Investment in Belize" sections of this MD&A.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar. The reporting currency of Belize Electricity
is the Belizean dollar, which is pegged to the US dollar at
BZ$2.00=US$1.00.
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Unfavourable
-- The impact of the discontinuance of the consolidation method of
accounting for Belize Electricity, effective June 20, 2011. For further
information, refer to the "Corporate Overview" and "Business Risk
Management - Investment in Belize" sections of this MD&A.
-- Tempered energy consumption due to persistent challenging economic
conditions in the region, a declining population, the high cost of fuel,
and the early and extended closure of certain hotel and other commercial
customers in the Turks and Caicos Islands resulting from a hurricane in
August 2011
-- Excluding Belize Electricity, electricity sales decreased 1% for the
quarter and 1% year to date
Favourable
-- Growth in the number of customers in Grand Cayman and the Turks and
Caicos Islands
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Unfavourable
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011
-- Approximately $4 million for the quarter and $14 million year to date of
unfavourable foreign exchange associated with the translation of foreign
currency-denominated revenue, due to the weakening of the US dollar
relative to the Canadian dollar period over period
-- Lower electricity sales
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
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Lower electricity sales
-- The discontinuance of the consolidation method of accounting for Belize
Electricity, effective June 20, 2011. There was no earnings contribution
from Belize Electricity year-to-date 2011, while the Company contributed
approximately $2 million in earnings for each of the third quarter and
year-to-date period in 2010.
-- Approximately $1 million associated with unfavourable foreign currency
translation year to date
Favourable
-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more
fuel-efficient production realized with the commissioning of new
generation units at the utility
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 111 134 (23) 277 290 (13)
Revenue ($ millions) 11 13 (2) 25 26 (1)
Earnings ($ millions) 8 9 (1) 13 14 (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 MW, 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 Quarterly and Year-to-Date Energy Sales Variances
Unfavourable
-- Decreased production in Belize, due to lower rainfall associated with a
longer dry season in 2011
-- Decreased production in Upper New York State for the quarter, due to a
generating plant being out of service
Favourable
-- Increased production in Upper New York State and Ontario year to date,
driven by higher rainfall
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Unfavourable
-- Decreased production in Belize
Favourable
-- Increased production and higher average energy sales rate per megawatt
hour ("MWh") in Ontario year to date. The average rate per MWh year-to-
date 2011 was $72.35 compared to $42.08 year-to-date 2010. Effective May
1, 2010, energy produced in Ontario is being sold under a fixed-price
contract with price indexing. Previously, energy was sold at market
rates.
-- Increased production in Upper New York State year to date
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Decreased production in Belize
-- Higher finance charges at Ontario operations as a result of lower
interest revenue associated with lower inter-company lending to
regulated operations in Ontario
Favourable
-- Increased production in Upper New York State year to date
-- Increased production and a higher average energy sales rate in Ontario
year to date
-- Lower administrative operating expenses at Ontario operations year to
date
-- Lower finance charges associated with operations in Belize
In May 2011 the generator at Moose River's hydroelectric generating facility in
Upper New York State sustained electrical damage. Equipment and business
interruption insurance have been claimed. The generator is under repair and the
facility is expected to be operational again in February 2012.
NON-REGULATED - FORTIS PROPERTIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality Revenue 47 44 3 123 120 3
Real Estate Revenue 16 16 - 50 49 1
----------------------------------------------------------------------------
Total Revenue 63 60 3 173 169 4
----------------------------------------------------------------------------
Earnings 9 9 - 18 19 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 22 hotels, including the Hilton
Suites Winnipeg Airport hotel acquired in October 2011, collectively
representing 4,300 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 Quarterly Revenue Variance
Favourable
-- A 5.9% increase in revenue per available room ("RevPar") at the
Hospitality Division to $94.83 for the third quarter of 2011 from $89.54
for the same quarter of 2010. RevPar increased due to an overall 4.5%
increase in the average daily room rate combined with an overall 1.4%
increase in hotel occupancy. The average daily room rate increased in
Atlantic Canada and western Canada, while occupancy increases were
achieved in Atlantic Canada and central Canada.
-- An increase in the occupancy rate at the Real Estate Division to 94.2%
as at September 30, 2011 from 93.7% as at September 30, 2010
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- A 2.1% increase in RevPar at the Hospitality Division to $80.54 year-to-
date 2011 from $78.89 year-to-date 2010. RevPar increased due to an
overall 2.8% increase in the average daily room rate, partially offset
by an overall 0.7% decrease in hotel occupancy. The average daily room
rate increased in all regions. Hotel occupancy in western Canada
decreased, while occupancy in Atlantic Canada and central Canada
increased.
-- A $0.5 million gain on the sale of the Viking Mall in rural Newfoundland
during the first quarter of 2011
-- Rent increases at the Real Estate Division
-- The increase in the occupancy rate at the Real Estate Division, as
discussed above for the quarter
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Higher corporate administrative expenses
-- Higher amortization costs year to date, mainly due to capital investment
in the Hospitality Division
-- A slight decline in performance at the Hospitality Division year to
date, mainly due to lower occupancy at hotels in western Canada,
partially offset by overall increased average room rates
Favourable
-- Improved performance at the Real Estate Division year to date,
reflecting the $0.5 million gain on the sale of the Viking Mall during
the first quarter of 2011
-- Improved performance at the Hospitality Division for the quarter, driven
by overall increased average room rates
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 25 8 17 40 23 17
Operating Expenses 3 3 - 7 13 (6)
Amortization 2 1 1 5 5 -
Finance Charges (2) 15 20 (5) 52 58 (6)
Corporate Tax Expense
(Recovery) 3 (4) 7 (3) (13) 10
------------------------------------------------------
2 (12) 14 (21) (40) 19
Preference Share
Dividends 7 7 - 22 21 1
----------------------------------------------------------------------------
Net Corporate and
Other Expenses (5) (19) 14 (43) (61) 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Quarterly and Year-to-Date Net Corporate and Other
Expenses Variances
Favourable
-- The $17 million (US$17.5 million) ($11 million after tax) fee paid to
Fortis in July 2011 and recorded in revenue, following upon the
termination of a Merger Agreement between Fortis and CVPS
-- Reduced operating expenses year to date. Operating expenses were higher
during the first half of 2010 due to business development costs incurred
during that period.
-- Lower finance charges. During the third quarter of 2011, finance charges
were reduced by a $7 million foreign exchange gain associated with the
translation of the US$88 million long-term other asset representing the
book value of the Corporation's former net investment in Belize
Electricity. The foreign exchange gain was partially offset by a $5.5
million ($4.5 million after tax) foreign exchange loss associated with
the translation of previously hedged US dollar-denominated debt. The
favourable net impact to earnings of the above foreign exchange impacts
was approximately $2.5 million.
-- Finance charges were also lower due to the refinancing of maturing
corporate debt at lower rates, the repayment of credit facility
borrowings during the quarter with a portion of the proceeds from the
common share offering in June and July 2011 and the favourable foreign
exchange impact associated with the translation of US dollar-denominated
interest expense.
Unfavourable
-- Higher preference share dividends year to date, due to the issuance of
First Preference Shares, Series H in January 2010
On July 11, 2011, the Board of Directors of CVPS determined that the unsolicited
acquisition proposal from Gaz Metro Limited Partnership was a "Superior
Proposal", as that term was defined in the Merger Agreement between Fortis and
CVPS announced on May 30, 2011, and CVPS elected to terminate the Merger
Agreement in accordance with its terms. Prior to such termination taking effect,
the Merger Agreement provided Fortis the right to require CVPS to negotiate with
Fortis for at least five business days with respect to any changes to the terms
of the Merger Agreement proposed by Fortis. Fortis agreed to waive such right in
exchange for the prompt payment by CVPS to Fortis of the US$17.5 million
termination fee plus US$2.0 million for expenses as set forth in the Merger
Agreement, thereby resulting in the termination of the Merger Agreement. Fortis
received the $18.8 million (US$19.5 million) payment on July 12, 2011.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
year-to-date 2011 are summarized as follows:
NATURE OF REGULATION
----------------------------------------------------------------------------
Supportive
Features
Future or
Allowed Historical
Common Test Year
Regulated Regulatory Equity Used to Set
Utility Authority (%) Customer Rates
Allowed Returns (%)
2009 2010 2011
----------------------------------------------------------------------------
ROE COS/ROE
----------------------------
FEI British 40 (1) 8.47 (2) 9.50 9.50 FEI: Prior to
Columbia /9.50 (3) January 1,
Utilities 2010, 50/50
Commission sharing of
("BCUC") 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 (2) 10.00 10.00
/10.00 (3)
FEWI BCUC 40 8.97 (2) 10.00 10.00 ROEs
/10.00 (3) established by
the BCUC,
effective July
1, 2009, as a
result of a
cost of
capital
decision in
the fourth
quarter of
2009.
Previously,
the allowed
ROEs were set
using an
automatic
adjustment
formula tied
to long-term
Canada bond
yields.
--------------
Future Test
Year
----------------------------------------------------------------------------
FortisBC BCUC 40 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
----------------------------------------------------------------------------
Fortis- Alberta 41 9.00 9.00 9.00 (4)COS/ROE
Alberta Utilities
Commission
("AUC")
ROE
established by
the AUC,
effective
January 1,
2009, as a
result of a
generic cost
of capital
decision in
the fourth
quarter of
2009.
Previously,
the allowed
ROE was set
using an
automatic
adjustment
formula tied
to long-term
Canada bond
yields.
--------------
Future Test
Year
----------------------------------------------------------------------------
Newfound- Newfoundland 45 8.95 +/- 9.00 +/- 8.38 +/-
land and 50 bps 50 bps 50 bps
Power Labrador
Board of
Commissioners
of
Public
Utilities
("PUB") COS/ROE
ROE for 2010
established by
the PUB.
Except for
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
----------------------------------------------------------------------------
Fortis- Ontario Canadian
Ontario Energy Niagara Power
Board ("OEB") 40 (5) 8.01 8.01 8.01 - COS/ROE
Canadian
Niagara Algoma Power -
Power COS/ROE and
subject to
Rural and
Remote Rate
Protection
("RRRP")
Program
Algoma Power 50 (6) 8.57 8.57 9.85 (7)
/40 (7)
Franchise Cornwall
Agreement Electric -
Cornwall Price cap with
Electric 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
Carib- Electricity N/A 9.00 - 7.75 - 7.75 - COS/ROA
bean Regulatory 11.00 9.75 9.75
Utilities Authority
("ERA")
Rate-cap
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 Utilities N/A 17.50 (8) 17.50 (8)17.50
Turks make (8)
and annual
Caicos filings to
the Governor COS/ROA
If the actual
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) Amount provided under licence.ROA achieved in 2009 and 2010 was
materially lower than the ROA allowed under the licence. Fortis Turks
and Caicos filed an Electricity Rate Variance Application in August
2011 requesting a change in the current rate structure and an overall
increase in base rates to government and commercial customers of
approximately 6%.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
----------------------------------------------------------------------------
Regulated Utility Summary Description
----------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review natural gas and propane commodity
rates with the BCUC every three months and mid-stream
rates annually, in order to ensure the flow-through rates
charged to customers are sufficient to cover the cost of
purchasing natural gas and propane and contracting for
mid-stream resources, such as third-party pipeline and/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
balance in the Commodity Cost Reconciliation Account is
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 and propane. 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 and
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.
Natural gas commodity rates remained unchanged as of April
1, 2011 and as of July 1, 2011, following the BCUC's
quarterly reviews of such rates.
- Effective October 1, 2011, rates for residential
customers in the Lower Mainland, Fraser Valley and
Interior, North and Kootenay service areas decreased by
approximately 5% to reflect changes in commodity costs,
following the BCUC's quarterly review of such rates.
- 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.
In July 2011 FEI received a decision from the BCUC that
approved the fuelling station infrastructure along with a
long-term contract with one counterparty for the supply of
compressed natural gas. The BCUC denied the Company's
application for a general tariff for the provision of
compressed natural gas and LNG for vehicles, unless
certain contractual conditions are met. The Company is
considering these proposed amendments in the context of
new natural gas vehicle stations.
- In July 2011 the BCUC approved the application jointly
filed by the FortisBC Energy companies and FortisBC
Electric requesting the utilities be permitted to adopt
United States generally accepted accounting principles
("US GAAP") effective January 1, 2012 for regulatory
reporting purposes.
- In July 2011 FEVI received a BCUC decision approving the
option for two First Nations bands to invest up to 15% of
the equity component of the capital structure of the new
LNG storage facility on Vancouver Island. If the option is
exercised, the equity investment by the First Nations
bands would occur effective January 1, 2012.
- In August 2011 FEI and FEVI received a decision from the
BCUC on the use of Energy Efficiency and Conservation
("EEC") Funds as incentives for natural gas vehicles
("NGVs"). The companies had made these funds available to
assist large customers in purchasing NGVs in lieu of
vehicles fueled by diesel. The decision determined that it
was not appropriate to use EEC funds for this purpose and
the BCUC has requested that the companies provide further
submissions to determine the prudency of the EEC
incentives at a future time.
- In January 2011 FEI filed a report of its review of its
Price Risk Management Plan ("PRMP") objectives with the
BCUC related to its gas commodity hedging plan and also
submitted a revised 2011-2014 PRMP. In July 2011 the BCUC
issued its decision on FEI's report and determined that
commodity hedging in the current environment was not a
cost-effective means of meeting the objectives of price
competitiveness and rate stability. The BCUC concurrently
denied FEI's 2011-2014 PRMP with the exception of certain
elements to address regional price discrepancies. As a
result, FEVI and FEI have suspended commodity-hedging
activities with the exception of limited swaps as
permitted by the BCUC. The existing hedging contracts are
expected to continue in effect through to their maturity
and the gas utilities' ability to fully recover the
commodity cost of gas in customer rates remains unchanged.
- In September 2011 the FortisBC Energy companies filed an
update to their 2012-2013 Revenue Requirements
Applications. FEI has requested an increase in rates of
3.2%, effective for each of January 1, 2012 and January 1,
2013, reflecting an increase in the delivery component of
customer rates. FEI's application assumes forecast average
rate base of approximately $2,754 million for 2012 and
$2,811 million for 2013. FEVI has requested that rates
remain unchanged for the two-year period commencing
January 1, 2012. FEVI's application assumes forecast
average rate base of $788 million for 2012 and $816
million for 2013. FEWI has requested an increase in rates
of approximately 6.5% effective January 1, 2012 and
approximately 4.3% effective January 1, 2013, reflecting
an increase in the delivery component of customer rates.
FEWI's application assumes forecast average rate base of
$42 million for 2012 and $41 million for 2013. The
requested rate increases are driven by ongoing investment
in utility infrastructure focused on system integrity and
reliability, and forecast increased operating expenses
associated with inflation, a heightened focus on safety
and security of the natural gas systems and increasing
compliance with codes and regulations. A decision on the
rate applications is expected late in the first quarter of
2012.
- In November 2011 FEI, FEVI and FEWI filed an application
with the BCUC for the amalgamation of the three companies
into one legal entity, and for the implementation of
common rates and services for the utilities' customers
across the province of British Columbia, effective January
1, 2013. The amalgamation requires approval by the BCUC
and consent of the Government of British Columbia.
----------------------------------------------------------------------------
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 infrastructure, including increased
amortization and interest expense.
- In June 2011 FortisBC Electric filed its 2012-2013
Revenue Requirements Application, which included its 2012-
2013 Capital Expenditure Plan, and its Integrated System
Plan ("ISP"). The ISP includes the Company's Resource
Plan, Long-Term Capital Plan and Long-Term Demand Side
Management Plan. FortisBC Electric requested an interim 4%
increase in customer electricity rates effective January
1, 2012 and a 6.9% increase effective January 1, 2013. The
rate increases are due to ongoing investment in utility
infrastructure, including increased costs of financing the
ongoing investment, and increasing power purchases driven
by customer growth and increased demand for electricity.
FortisBC Electric's rate application assumes forecast
average rate base of approximately $1,145 million for 2012
and $1,212 million for 2013. The requested capital
expenditures are $111 million for 2012 and $134 million
for 2013, before customer contributions. A decision on the
rate application is expected late 2011 or early 2012.
- Effective June 1, 2011, the BCUC approved a refundable
interim increase of 1.4% in FortisBC Electric customer
electricity rates arising from an increase in purchased
power costs due to an interim increase in BC Hydro rates.
----------------------------------------------------------------------------
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 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 has been
completed and a decision is expected in the fourth quarter
of 2011.
- In March 2011 FortisAlberta filed its 2012 and 2013 DTA.
The Company 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 requested rate
increases are driven primarily by ongoing investment in
utility infrastructure, including increased amortization
and interest expense. At FortisAlberta's request, the AUC
is allowing FortisAlberta to settle the DTA through
negotiation, but has stipulated that the negotiation apply
only to 2012 rates.
- In June 2011 the AUC issued its decision regarding the
prudency of additional capital expenditures above $104
million related to the Company's Automated Metering
Project. In its decision, the AUC concluded that the full
amount of the forecasted total project cost of $126
million can be included in rate base and collected in
customer rates. The impact of the decision was the
recognition of $3 million in accrued revenue and an
associated regulatory asset as at September 30, 2011. The
Utilities Consumer Advocate had filed a Leave to Appeal
related to this decision. During the third quarter of
2011, the Leave to Appeal request was withdrawn upon
consent of all parties and no further court proceedings
remain related to the above matter.
- 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 customers
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 electricity distribution rates.
FortisAlberta is currently assessing PBR and will
participate fully in the AUC process. In July 2011
FortisAlberta, along with other distribution utilities
operating under the AUC's jurisdiction, submitted their
PBR proposals to the AUC. The Company's submission
outlines its views as to how PBR should be implemented at
FortisAlberta.
----------------------------------------------------------------------------
Newfoundland - In November 2010 the PUB approved Newfoundland Power's
Power application to defer the recovery of expected increased
costs in 2011 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 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, including Bell Aliant
buying back 40% of all joint-use poles and related
infrastructure from Newfoundland Power representing
approximately 5% of the Company's rate base. The new
support structure arrangements were subject to certain
conditions, including PUB approval of the sale of the
joint-use poles. The PUB issued an order approving the
sale of the joint-use poles in September 2011. Effective
January 1, 2011, Newfoundland Power is no longer receiving
pole rental revenue from Bell Aliant. Newfoundland Power
is responsible for the construction and maintenance of
Bell Aliant's support structure requirements throughout
2011. The new support structure arrangements are not
expected to materially impact Newfoundland Power's ability
to earn a reasonable return on its rate base in 2011.
Proceeds of approximately $46 million from the sale of 40%
of the joint-use poles were received by Newfoundland Power
from Bell Aliant in October 2011. The final sale price for
the poles is subject to adjustment upon completion of a
pole survey later in 2011. The sale proceeds were used to
pay down credit facility borrowings and pay a special
dividend of approximately $30 million to Fortis in order
to maintain Newfoundland Power's capital structure at 45%
common equity.
- In April 2011 the PUB approved Newfoundland Power's
application requesting an Optional Seasonal Rate ("OSR")
for domestic customers, effective July 1, 2011. The OSR
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
capital expenditures for 2011 required to facilitate
implementation of the OSR and the use of an OSR Revenue
and Cost Recovery Account that provides for the deferral
of annual cost and revenue effects associated with
implementing the OSR.
- Effective July 1, 2011, the PUB approved an overall
average increase in customer electricity rates of 7.7%.
The increase in rates was primarily 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 increase in rates,
principally due to increased fuel prices, will have no
impact on Newfoundland Power's earnings.
- In July 2011 Newfoundland Power filed an application
with the PUB requesting approval for its 2012 Capital
Expenditure Plan totalling approximately $77 million.
- In September 2011 Newfoundland Power filed an
application with the PUB requesting the deferred recovery
of expected increased costs in 2012 of $2.4 million, due
to expiring regulatory amortizations in 2012. The
application was approved in October 2011.
- As part of its 2011 Budget, the Government of
Newfoundland and Labrador introduced the Energy Rebate,
effective October 1, 2011, in which the 8% provincial
portion of the Harmonized Goods and Services Tax on home
energy purchases, including electricity, is being refunded
to residential customers.
----------------------------------------------------------------------------
Maritime Electric - In November 2010 Maritime Electric signed the PEI Energy
Accord (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 incremental 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. 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, incremental 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.
- The nature and timing of the recovery of the deferred
costs related to Point Lepreau is subject to further
review by the PEI Energy Commission (the "Commission"),
which was recently established by the Government of PEI.
Having authority under the Public Inquiries Act, the co-
chaired five-member Commission's goal is to examine and
provide advice on ways in which PEI's cost of electricity
can be structurally reduced and/or stabilized over the
longer term. In carrying out this goal, the Commission
will, amongst other things, examine and provide
recommendations on long-term ownership and management of
electricity on PEI and provide advice and recommendations
as to the future role of the PEI Energy Corporation, IRAC
(as it relates to electricity) and the Office of Energy
Efficiency.
- 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 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 overall by approximately 14%,
effective March 1, 2011, reflecting a decrease in the
Energy Cost Adjustment Mechanism ("ECAM") component of
customer rates, partially offset by an increase in the
base component of customer rates. A two-year customer rate
freeze commenced after the March 1, 2011 rate adjustment.
----------------------------------------------------------------------------
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 in 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 overall 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. Algoma Power has consulted with the
intervener community 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. The balance of Algoma Power's
revenue requirement is recovered from the RRRP Program. In
September 2011 Algoma Power filed its first Third-
Generation IRM application for customer electricity
distribution rates, effective January 1, 2012. The Third-
Generation IRM maintains the allowed ROE at 9.85% for
2012. Algoma Power has proposed that both electricity
rates and funding under the RRRP Program be indexed.
- During the fourth quarter of 2011, FortisOntario expects
to file a Third-Generation IRM application for its
operations in Port Colborne and a similar, but harmonized,
rate application for its operations in Fort Erie and
Gananoque. The Third-Generation IRM maintains the allowed
ROE at 8.01% for 2012. The OEB is expected to publish the
applicable inflation factor and efficiency targets under
the IRM during the first quarter of 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.
----------------------------------------------------------------------------
Caribbean - In March 2011 Caribbean Utilities confirmed to the ERA
Utilities 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 on
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.
- In July 2011 the ERA approved Caribbean Utilities
request to use US GAAP for regulatory reporting purposes,
beginning January 1, 2012.
- In August 2011 Caribbean Utilities requested and
received expressions of interest and preliminary proposals
for the financing, construction, ownership and operation
of renewable energy generation facilities. It is the
Company's intention to accept up to 13 MW in aggregate of
grid-connected renewable energy generators on Grand
Cayman. Potential investors would become independent power
producers that will enter into power purchase agreements
("PPAs") with the Company for the supply of electricity
from the alternative energy generators. The PPAs are
subject to ERA review and approval. An evaluation of the
expressions of interest received is expected by the end of
2011.
- Caribbean Utilities will be filing its 2012-2016 CIP
during the fourth quarter of 2011.
----------------------------------------------------------------------------
Fortis Turks and - In March 2011 Fortis Turks and Caicos submitted its 2010
Caicos 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 of US$142 million for 2010 and cumulative
shortfall in achieving allowable profits of US$49 million
as at December 31, 2010.
- In August 2011 Fortis Turks and Caicos filed with the
interim Government of the Turks and Caicos Islands an
Electricity Rate Variance Application, which requested a
change in the rate structure and an overall approximate 6%
increase in base rates to government and commercial
customers. A response to the application is expected
during the fourth quarter of 2011.
- An independent review of the regulatory framework for
the electricity sector in the Turks and Caicos Islands was
performed during the third quarter of 2011 on behalf of
the interim Government of the Turks and Caicos Islands.
The purpose of the review was to: (i) assess the
effectiveness of the current regulatory framework in terms
of its administrative and economic efficiency; (ii) assess
the current and proposed electricity costs and tariffs in
the Turks and Caicos Islands in relation to comparable
regional and international utilities; (iii) make
recommendations for a revised regulatory framework and
Electricity Ordinance; and (iv) make recommendations for
the implementation and operation of the revised regulatory
framework.
- Earlier in 2011, the interim Government of the Turks and
Caicos Islands publicly stated its intention to implement
a carbon tax, effective September 2011, that would be
applicable to Fortis Turks and Caicos but which may not be
permitted to be passed on to Fortis Turks and Caicos'
customers. To date, no carbon tax has been implemented.
Under the terms of an agreement with the Government of the
Turks and Caicos Islands when Fortis Turks and Caicos was
granted its licence, the Company is exempt from any taxes
other than customs duties where applicable by law.
----------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between September 30, 2011 and December 31, 2010.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
September 30, 2011 and December 31, 2010
----------------------------------------------------------------------------
Balance Sheet Increase/
Account (Decrease) Explanation
($ millions)
----------------------------------------------------------------------------
Accounts (186) The decrease was driven by the
receivable FortisBC Energy companies, mainly
due to a seasonal decrease in sales
and the lower commodity cost of
natural gas reflected in customer
rates.
----------------------------------------------------------------------------
Regulatory assets 52 The increase was mainly due to an
- increase in the deferral of: (i)
current and long- future income taxes; (ii) Alberta
term Electric System Operator ("AESO")
charges and operating costs at
FortisAlberta; (iii) various
miscellaneous costs as permitted by
the regulator at the FortisBC
Energy companies; and (iv) fuel
costs at Caribbean Utilities.
The above increases were partially
offset by the deferral at the
FortisBC Enegy companies associated
with the change in the fair market
value of the natural gas
derivatives, and a decrease in the
2010 accrued distribution revenue
adjustment rider at FortisAlberta
as it is being collected in 2011
rates.
----------------------------------------------------------------------------
Inventories 26 The increase was driven by the
normal seasonal increase of gas in
storage at the FortisBC Energy
companies, partially offset by the
impact of lower natural gas
commodity prices.
----------------------------------------------------------------------------
Other assets 116 The increase was due to the
discontinuance of the consolidation
method of accounting for Belize
Electricity in June 2011, due to
the expropriation of the Company by
the GOB, and the resulting
classification of the book value of
the Corporation's previous
investment in Belize Electricity,
including reclassified unrealized
foreign currency translation losses
of $28 million, to long-term other
assets.
----------------------------------------------------------------------------
Utility capital 305 The increase primarily related to
assets $747 million invested in
electricity and gas systems and the
impact of foreign exchange on the
translation of US dollar-
denominated utility capital assets,
partially offset by the impact of
the discontinuance of the
consolidation method of accounting
for Belize Electricity, and
amortization costs and customer
contributions year-to-date 2011.
----------------------------------------------------------------------------
Short-term (116) The decrease was driven by lower
borrowings borrowings at the FortisBC Energy
companies, due to seasonality of
operations and the repayment of
borrowings using proceeds from an
equity injection from Fortis.
----------------------------------------------------------------------------
Accounts payable (100) The decrease was mainly due to: (i)
and accrued the change in the fair market value
charges of the natural gas derivatives at
the FortisBC Energy companies; (ii)
the timing of payment of property
taxes and franchise fees at the
FortisBC Energy companies; (iii)
lower amounts owing for purchased
natural gas at the FortisBC Energy
companies and purchased power at
Newfoundland Power, associated with
seasonality of operations; and (iv)
the discontinuance of the
consolidation method of accounting
for Belize Electricity. The
decrease was partially offset by
higher payables associated with
transmission-connected projects and
cost accruals at FortisAlberta and
higher accounts payable at the
Waneta Expansion Limited
Partnership ("Waneta Partnership")
associated with the construction of
the Waneta hydroelectric generation
expansion project ("Waneta
Expansion Project").
----------------------------------------------------------------------------
Regulatory 35 The increase was mainly due to: (i)
liabilities - increased deferrals at the FortisBC
current and long- Energy companies; (ii) an increase
term in the provision for asset removal
and site restoration costs at
FortisAlberta; (iii) increases in
the weather normalization and other
deferral accounts at Newfoundland
Power; and (iv) an increase in the
ECAM account at Maritime Electric.
The increased deferrals at the
FortisBC Energy companies were
associated with the Rate
Stabilization Deferral Account,
reflecting the accumulation of
over-recovered costs of providing
service to customers during 2011
and the Revenue Stabilization
Adjustment Mechanism, reflecting
the margin impact of actual gas
volumes consumed by residential and
commercial customers being in
excess of forecast gas volumes.
The above increases were partially
offset by the impact of the
discontinuance of the consolidation
method of accounting for Belize
Electricity.
----------------------------------------------------------------------------
Future income tax 41 The increase was driven by tax
liabilities - timing differences related to
current and long- capital expenditures at the
term FortisBC Energy companies,
FortisAlberta and FortisBC
Electric.
----------------------------------------------------------------------------
Long-term debt and (70) The decrease was driven by the
capital lease repayment of the Corporation's
obligations committed credit facility
(including borrowings with a portion of the
current portion) proceeds from the June and July
2011 $341 million common share
issue and the discontinuance of the
consolidation method of accounting
for Belize Electricity. The
decrease was partially offset by
higher committed credit facility
borrowings at FortisAlberta and the
issuance of US$40 million of long-
term debt by Caribbean Utilities in
support of the companies' capital
expenditure programs, and the
impact of foreign exchange on the
translation of US dollar-
denominated debt.
----------------------------------------------------------------------------
Shareholders' 504 The increase was driven by the
equity issuance of $341 million in common
(before non- shares in June and July 2011.
controlling
interests) The remainder of the increase in
shareholders' equity was primarily
due to: (i) the reclassification of
$28 million of unrealized foreign
currency translation losses related
to the Corporation's previous
investment in Belize Electricity
from accumulated other
comprehensive loss to long-term
other assets; (ii) net earnings
attributable to common equity
shareholders year-to-date 2011,
less common share dividends; and
(iii) the issuance of common shares
under the Corporation's dividend
reinvestment and stock option
plans.
----------------------------------------------------------------------------
Non-controlling 43 The increase was driven by advances
interests from the 49% non-controlling
interests in the Waneta
Partnership.
----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the three and nine months ended September 30, 2011, as compared to the same
periods in 2010, followed by a discussion of the nature of the variances in cash
flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of Period 298 71 227 109 85 24
Cash Provided by (Used in):
Operating Activities 151 129 22 678 534 144
Investing Activities (269) (253) (16) (756) (658) (98)
Financing Activities (73) 117 (190) 76 103 (27)
Effect of Exchange Rate
Changes on Cash and Cash
Equivalents 1 - 1 1 - 1
----------------------------------------------------------------------------
Cash, End of Period 108 64 44 108 64 44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $22 million higher quarter over quarter and $144
million higher year to date compared to the same period last year. The increases
were driven by higher earnings and favourable changes in working capital,
partially offset by unfavourable changes in regulatory deferral accounts. The
favourable working capital changes were driven by the greater impact of
seasonality at the FortisBC Energy companies and an increase in accounts payable
and the collection from customers of the 2010 accrued distribution revenue
adjustment rider at FortisAlberta, partially offset by unfavourable working
capital changes at Maritime Electric. Lower AESO net transmission-related
receipts and payments at FortisAlberta had an unfavourable impact on both
working capital and regulatory deferral accounts. Changes in regulatory deferral
accounts at the FortisBC Energy companies also had an unfavourable impact on
cash flow from operating activities quarter over quarter.
Investing Activities: Cash used in investing activities was $16 million higher
quarter over quarter mainly due to capital spending related to the non-regulated
Waneta Expansion Project, partially offset by lower capital spending at
FortisAlberta. Cash used in investing activities was $98 million higher year to
date compared to the same period last year due to capital spending related to
the non-regulated Waneta Expansion Project, partially offset by lower capital
spending at FortisBC Electric and an increase in contributions received in aid
of construction.
Financing Activities: The decrease in cash provided by financing activities for
the quarter and year to date was due to higher net repayments under committed
credit facilities classified as long-term and changes in short-term borrowings,
partially offset by: (i) higher proceeds from the issuance of common shares;
(ii) lower repayments of long-term debt; (iii) higher advances from
non-controlling interests; and (iv) higher proceeds from long-term debt.
Proceeds from the issuance of preferences shares were also lower year to date
compared to the same period in 2010.
Net proceeds from short-term borrowings were $85 million for the quarter
compared to $122 million for the same quarter last year. Net repayments of
short-term borrowings were $115 million year to date compared to $4 million for
the same period last year. The changes in short-term borrowings were driven by
the FortisBC Energy companies, due to seasonality differences and timing of
repayments using proceeds from equity injections from the Corporation, and
Caribbean Utilities.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease obligations and net borrowings under committed credit
facilities for the quarter and year to date compared to the same periods last
year are summarized in the following tables.
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caribbean Utilities (1) 9 - 9 38 - 38
Other - - - 1 - 1
----------------------------------------------------------------------------
Total 9 - 9 39 - 39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Issued 15-year US$15 million 4.85% and 20-year US$25 million 5.10%
unsecured notes. The first tranche of US$30 million was issued in June
2011 and the second tranche of US$10 million was issued in July 2011.
The net proceeds were used to repay current installments on long-term
debt and short-term borrowings and to finance capital expenditures.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy
Companies - - - - (1) 1
FortisBC Electric - - - - (1) 1
Maritime Electric - - - - (15) 15
Caribbean Utilities - - - (12) (15) 3
Fortis Properties (2) (1) (1) (6) (53) 47
Corporate (1) - - - - (125) 125
Other - (2) 2 (6) (5) (1)
----------------------------------------------------------------------------
Total (2) (3) 1 (24) (215) 191
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) In April 2010 FHI redeemed in full for cash its $125 million 8% Capital
Securities with proceeds from borrowings under the Corporation's
committed credit facility.
----------------------------------------------------------------------------
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta 33 22 11 50 82 (32)
FortisBC Electric (7) 15 (22) - 27 (27)
Newfoundland Power (13) (18) 5 10 (5) 15
Corporate (191) 17 (208) (165) 89 (254)
----------------------------------------------------------------------------
Total (178) 36 (214) (105) 193 (298)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $20 million for the quarter and $76 million year to
date were received from non-controlling interests in the Waneta Partnership to
finance capital spending related to the Waneta Expansion Project.
In June 2011 Fortis publicly issued 9.1 million common shares for gross proceeds
of approximately $300 million. In July 2011 an additional 1.24 million common
shares of Fortis were publicly issued upon the exercise of an over-allotment
option, resulting in gross proceeds of approximately $41 million. The total net
proceeds from the common share offering of $327 million were used to repay
borrowings under credit facilities and finance equity injections into the
regulated utilities in western Canada and the non-regulated Waneta Expansion
Project, in support of infrastructure investment, and for general corporate
purposes.
In January 2010 Fortis completed a $250 million public offering of 10 million
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 during the third quarter of 2011 were $38 million,
net of $16 million in dividends reinvested, compared to $33 million, net of $15
million in dividends reinvested, paid during the same quarter of 2010. Common
share dividends paid year-to-date 2011 were $109 million, net of $47 million in
dividends reinvested, compared to $102 million, net of $43 million in dividends
reinvested, paid year-to-date 2010. The dividend paid per common share for each
of the first three quarters of 2011 was $0.29 compared to $0.28 for each of the
first three quarters of 2010. The weighted average number of common shares
outstanding for the third quarter and year to date were 186.5 million and 179.5
million, respectively, compared to 173.2 million and 172.4 million, for the
third quarter and year to date, respectively, in 2010.
CONTRACTUAL OBLIGATIONS
Consolidated contractual obligations of Fortis over the next five years and for
periods thereafter, as at September 30, 2011, are outlined in the following
table. A detailed description of the nature of the obligations is provided in
the MD&A for the year ended December 31, 2010 and below, where applicable.
----------------------------------------------------------------------------
Contractual Obligations
(Unaudited) Due Due in Due in Due
As at September 30, 2011 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 5,595 88 439 817 4,251
Waneta Partnership promissory
note 72 - - - 72
Brilliant Terminal Station 59 3 5 5 46
Gas purchase contract
obligations (1) 433 258 170 5 -
Power purchase obligations (2)
FortisBC Electric 2,877 44 87 83 2,663
FortisOntario 420 42 98 103 177
Maritime Electric 203 55 77 57 14
Capital cost (3) 465 18 35 36 376
Joint-use asset and share
service agreements 64 4 8 7 45
Office lease - FortisBC Electric 18 2 4 3 9
Operating lease obligations 148 20 33 31 64
Defined benefit pension funding
contributions (4) 66 30 32 1 3
Other 21 4 7 6 4
----------------------------------------------------------------------------
Total 10,441 568 995 1,154 7,724
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on index prices as at September 30, 2011
(2) Excludes power purchase obligations of Belize Electricity, due to the
discontinuance of the consolidation method of accounting for the
utility, effective June 20, 2011
(3) 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.
(4) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than 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, 2011 Newfoundland Power
December 31, 2012 FortisBC Energy companies (covering non-unionized
employees)
December 31, 2013 FortisBC Energy companies (covering unionized employees)
December 31, 2013 FortisBC Electric
The estimate of defined benefit pension funding
contributions above includes the impact of the outcome
of the December 31, 2010 actuarial valuations, completed
during the first half of 2011, associated with the
defined benefit pension plans at the FortisBC Energy
companies, covering unionized employees, and at FortisBC
Electric, as well as other revised actuarial estimates.
Other contractual obligations, which are not reflected in the above table, did
not materially change from those 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
September 30, 2011 December 31, 2010
($ millions) (%) ($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,729 54.8 5,914 58.4
Preference shares (2) 912 8.7 912 9.0
Common shareholders' equity 3,809 36.5 3,305 32.6
----------------------------------------------------------------------------
Total (3) 10,450 100.0 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
The change in the capital structure was driven by the public issuance of
approximately $341 million in common shares in June and July 2011, combined with
common shares issued under the Corporation's dividend reinvestment and stock
option plans and the reclassification of unrealized foreign currency translation
losses related to the Corporation's previous investment in Belize Electricity to
long-term other assets. Also contributing to the change in the capital structure
was net earnings applicable to common shares, net of dividends, and lower
borrowings under credit facilities.
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)
During the third quarter of 2011, DBRS confirmed the Corporation's existing debt
credit rating at A(low). 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, 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 $806 million in gross capital expenditures by segment
year-to-date 2011 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date September 30, 2011
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Total Regu-
lated Regu- lated
Electric lated Electric
Utili- Utili- Utili- Non-
FortisBC New- ties ties ties Regu-
Energy Fortis found- - - - lated - Fortis
Com- Alberta FortisBC land Cana- Cana- Carib- Utility Proper-
panies (2) Electric Power dian dian bean(3) (4) ties Total
----------------------------------------------------------------------------
179 253 78 55 33 598 57 131 20 806
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
AFUDC.
(2) Includes payments made to AESO for investment in transmission-related
capital projects
(3) Includes capital expenditures at Belize Electricity up to June 20, 2011
(4) 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 have been no material changes in the overall expected level, nature and
timing of the Corporation's significant capital projects that were disclosed in
the MD&A for the year ended December 31, 2010, except as described below.
In August 2011 Fortis Properties received municipal government approval to
construct a $50 million 12-storey office building in downtown St. John's,
Newfoundland. The building will feature 152,000 square feet of Class A office
space and include 262 parking spaces. Construction is expected to be completed
in the second half of 2013.
Approximately $33 million of the capital cost of FEI's Customer Care Enhancement
Project is expected to be incurred in the first half of 2012, up from the
original estimate of $10 million expected to be incurred in 2012 as disclosed as
at December 31, 2010. The estimated total project cost remains unchanged at $116
million and the in-house customer care function is expected to come on-line
starting January 2012.
During 2011 FortisAlberta continued with the replacement of vintage poles under
its pole management program, which involves 96,000 poles in total, to prevent
risk of failure due to age. The total capital cost of the program through to
2019 is now expected to be approximately $335 million, an increase from the $283
million forecast as at December 31, 2010. The increase is primarily due to a
revised forecast estimating higher labour and material costs later in the
project.
During the first quarter of 2011, FortisAlberta substantially completed its $126
million Automated Metering Project, which involved the replacement of
approximately 466,000 conventional meters.
During the second quarter of 2011, FEI substantially completed construction of
its estimated $214 million LNG storage facility. The facility is substantially
filled and will be available for the upcoming winter-heating season.
During the third quarter of 2011, the second new 9-MW diesel-powered generating
unit at Fortis Turks and Caicos came into service. The third unit is expected to
be delivered in 2014 with the total cost of the three units estimated at
approximately $29 million.
During the fall of 2011, FortisBC Electric substantially completed its $105
million Okanagan Transmission Replacement Project.
Construction progress on the $900 million Waneta Expansion Project is going well
and the project is currently on schedule. Major construction activities on-site
include excavation of the intake, powerhouse and power tunnels.
Over the five-year period 2011 through 2015, consolidated gross capital
expenditures are expected to be approximately $5.7 billion, up from $5.5 billion
as disclosed in the MD&A for the year ended December 31, 2010. The increase
largely reflects higher capital expenditures at the FortisBC Energy companies,
partially offset by the exclusion of capital expenditures at Belize Electricity
due to the discontinuance of the consolidation method of accounting for the
Company. Approximately 61% of the capital spending is expected to be incurred at
the regulated electric utilities, driven by FortisAlberta and FortisBC Electric.
Approximately 23% and 16% 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 that 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 September 30, 2011, management expects consolidated long-term debt
maturities and repayments to average approximately $270 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 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 $56 million as at September 30, 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 the Exploits Partnership, as discussed above, Fortis and
its subsidiaries were in compliance with debt covenants as at September 30, 2011
and are expected to remain compliant throughout the remainder of 2011.
CREDIT FACILITIES
As at September 30, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.3 billion, of which $1.9 billion was
unused, including the Corporation's unused $800 million committed revolving
credit facility. The credit facilities are syndicated mostly with the seven
largest Canadian banks, with no one bank holding more than 20% of these
facilities. Approximately $2.2 billion of the total credit facilities are
committed facilities with maturities between 2012 and 2015.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
----------------------------------------------------------------------------
Credit Facilities (Unaudited) As at
September December
Corporate Regulated Fortis 30, 31,
($ millions) and Other Utilities Properties 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit
facilities 845 1,490 13 2,348 2,109
Credit facilities
utilized:
Short-term
borrowings - (239) (3) (242) (358)
Long-term debt
(including current
portion) - (114) - (114) (218)
Letters of credit
outstanding (1) (65) - (66) (124)
----------------------------------------------------------------------------
Credit facilities
unused 844 1,072 10 1,926 1,409
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 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 renegotiated and amended its 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.
In April 2011 FHI extended the maturity date of its $30 million unsecured
committed revolving credit facility to May 2012.
In June 2011 Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility, obtaining an extension to the maturity of
the facility to August 2015 from August 2013. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
In August 2011 the Corporation renegotiated and amended its unsecured committed
revolving credit facility, increasing the amount available under the facility to
$800 million from $600 million and extending the maturity date of the facility
to July 2015 from May 2012. At any time prior to maturity, the Corporation may
provide written notice to increase the amount available under the facility to $1
billion. The amended credit facility agreement reflects an increase in pricing
but, otherwise, contains substantially similar terms and conditions as the
previous credit facility agreement.
In September 2011 FortisAlberta amended its unsecured committed revolving credit
facility to increase the amount available under the facility to $250 million
from $200 million and extend the maturity date to September 2015 from May 2012.
The amended credit facility agreement reflects an increase in pricing.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows:
----------------------------------------------------------------------------
Financial Instruments
(Unaudited) As at
September 30, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Waneta Partnership
promissory note 44 47 42 40
Long-term debt, including
current portion (1) 5,595 6,728 5,669 6,431
Preference shares,
classified as debt (2) 320 345 320 344
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Carrying value as at September 30, 2011 excludes unamortized deferred
financing costs of $41 million (December 31, 2010 - $42 million) and
capital lease obligations of $41 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
$616 million as at September 30, 2011 (December 31, 2010 - $615
million).
Excluded from the above table is the $120 million long-term other asset as at
September 30, 2011 related to the Corporation's previous investment in Belize
Electricity. The fair value of this financial asset is not determinable at this
time.
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 investments 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. Foreign exchange gains and losses on the translation of US
dollar-denominated interest expense partially offsets the foreign exchange
losses and gains on the translation of the Corporation's foreign subsidiaries'
earnings, which are denominated in US dollars. The reporting currency of
Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation and
BECOL is the US dollar.
As at September 30, 2011, US$550 million of the US$590 million corporately
issued long-term debt (December 31, 2010 - US$590 million of US$590 million) had
been designated as an effective hedge of the Corporation's net investments in
self-sustaining foreign subsidiaries. Foreign currency exchange rate
fluctuations associated with the translation of the Corporation's corporately
issued US dollar borrowings designated as effective hedges are recognized in
other comprehensive income and help offset unrealized foreign currency gains and
losses on the net investments in self-sustaining foreign subsidiaries, which are
also recognized in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with its previous
investment in Belize Electricity, recorded in long-term other assets, does not
qualify for hedge accounting as Belize Electricity is no longer a
self-sustaining foreign subsidiary of Fortis. As a result, as at September 30,
2011, approximately US$40 million of corporately issued debt that previously
hedged the former investment in Belize Electricity is not an effective hedge.
Effective June 20, 2011, foreign exchange gains and losses on the translation of
the asset associated with Belize Electricity and the corporately issued US
dollar-denominated debt that previously qualified as a hedge of the investment
are required to be recognized in earnings. As a result, the Corporation
recognized a net after-tax foreign exchange gain of approximately $2.5 million
in earnings during the quarter ended September 30, 2011. As at September 30,
2011, all of the Corporation's net investments in self-sustaining foreign
subsidiaries were hedged (December 31, 2010 - 99%).
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes.
The following table summarizes the valuation of the Corporation's derivative
financial instruments.
----------------------------------------------------------------------------
Derivative Financial Instruments
(Unaudited) As at
September 30, 2011 December 31, 2010
Estimated Estimated
Carrying Fair Carrying Fair
Term to Number Value Value Value Value
Maturity of ($ ($ ($ ($
Liability (years) Contracts millions) millions) millions) millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign
exchange
forward
contract less than
1 1 - - - -
Fuel option less than
contracts 1 2 (1) (1) - -
Natural gas
derivatives
:
Swaps and
options Up to 3 201 (101) (101) (162) (162)
Gas purchase
contract
premiums Up to 2 85 (3) (3) (5) (5)
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----------------------------------------------------------------------------
The foreign exchange forward contract is held by FEI. During 2010 FEI entered
into a foreign exchange forward contract to hedge the cash flow risk related to
approximately US$5 million remaining to be paid under a contract for the
implementation of a customer information system. FEVI was also party to a
foreign exchange forward contract to hedge the cash flow risk related to US
dollar payments under a contract for the construction of the LNG storage
facility on Vancouver Island. During the third quarter of 2011, FEVI's foreign
exchange forward contract matured.
The fuel option contracts are held by Caribbean Utilities. During the first
quarter of 2011, the Company's Fuel Price Volatility Management Program was
approved by the regulator to reduce the impact of volatility in fuel prices on
customer rates. In April 2011 Caribbean Utilities entered into two fuel option
contracts.
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, to temper gas price
volatility on customer rates and to reduce the risk of regional price
discrepancies. For further information, refer to the "Material Regulatory
Decisions and Applications - FEI" section of this MD&A.
The changes in the fair values of the foreign exchange forward contract, fuel
option 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 derivative financial
instruments were recorded in accounts payable as at September 30, 2011 and as at
December 31, 2010.
The foreign exchange forward contract is valued using the present value of cash
flows based on a market foreign exchange rate and the foreign exchange forward
rate curve. The fuel option contracts are valued using published market prices
for similar commodities. 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
contract, fuel option contracts and natural gas derivatives are estimates of the
amounts that would have to be received or paid 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 $66 million, as at
September 30, 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
year-to-date 2011 from those disclosed in the MD&A for the year ended December
31, 2010, except for those described below.
Investment in Belize: In June 2011 the GOB expropriated the Corporation's
investment in Belize Electricity. Fortis has commissioned an independent
valuation of its previous investment in Belize Electricity and expects to submit
its claim to the GOB for compensation during the fourth quarter of 2011. The
Corporation is exposed to risk associated with the amount of compensation to be
paid for its previous investment in Belize Electricity, the timeliness of
payment of the compensation and the ability of the GOB to pay the compensation
owing to Fortis. The book value of the Corporation's previous investment in
Belize Electricity recorded in long-term other assets on the consolidated
balance sheet of Fortis was $120 million as at September 30, 2011.
The Prime Minister of Belize has stated that it is not the GOB's intention to
expropriate BECOL. As at September 30, 2011, the book value of the Corporation's
investment in BECOL was $159 million.
For further information, refer to the "Corporate Overview" section of this MD&A.
Economic Conditions: The Corporation's service territory in the Caribbean region
continues to be impacted by challenging economic conditions. The population on
Grand Cayman and the Turks and Caicos Islands has been declining as many
non-locals working in the construction industry have returned to their home
countries or other jurisdictions, as a result of the strong retraction in
construction activity due to the weak local economies.
On the positive side, the recent completion and commissioning of phase one of a
local airport expansion at the principal airport in Providenciales in the Turks
and Caicos Islands in September 2011 should help foster future economic growth,
mainly in the tourism and commercial sectors, allowing direct flights from
Europe and accommodating more flights from North America. On Grand Cayman,
several residential, resort and commercial projects are being completed in 2011,
which have the potential to increase load and electricity sales for Caribbean
Utilities.
Any sustained recovery of the economy in the Caribbean region, however, will
hinge on the recovery of the U.S. economy. In line with the general U.S.
economic forecast, it is expected that the current local economic weakness in
the Caribbean region will continue into 2012 and possibly 2013, resulting in
little-to-no growth in electricity sales for Caribbean Utilities and Fortis
Turks and Caicos during those years.
Transition to New Accounting Standards: In June 2011 the Ontario Securities
Commission ("OSC") issued a decision allowing Fortis and its reporting issuer
subsidiaries to prepare their financial statements, effective January 1, 2012,
in accordance with US GAAP without qualifying as U.S. Securities and Exchange
Commission ("SEC") Issuers. The Corporation and its reporting issuer
subsidiaries, therefore, will be adopting US GAAP as opposed to International
Financial Reporting Standards ("IFRS") on January 1, 2012. Earnings to be
recognized under US GAAP are expected to be closely aligned with earnings
recognized under Canadian GAAP, mainly due to the continued recognition of
regulatory assets and liabilities under US GAAP. A transition to IFRS would
likely have resulted in the derecognition of some, or perhaps all, of the
Corporation's regulatory assets and liabilities and significant volatility in
the Corporation's consolidated earnings. For further information, refer to the
"Future Accounting Standards" section of this MD&A.
Capital Resources and Liquidity Risk - Credit Ratings: Fortis and its regulated
utilities do not anticipate any material adverse rating actions by the credit
rating agencies in the near term. Year-to-date 2011, DBRS confirmed its existing
credit ratings for Newfoundland Power, Caribbean Utilities, FortisBC Electric,
Fortis, FHI and FEI. Also, Moody's Investors Service confirmed its existing
credit ratings for Newfoundland Power and FEI, while S&P downgraded Caribbean
Utilities credit rating from A to A- due to a weak customer market and increased
business risks, but maintained its existing credit rating for Maritime Electric.
Defined Benefit Pension Plan Assets: As at September 30, 2011, the fair value of
the Corporation's consolidated defined benefit pension plan assets was $751
million, up $24 million or 3%, 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 on
January 31, 2011. The Company and COPE have commenced negotiations. In the
interim, the current collective agreement remains in full effect until such time
as the parties negotiate and ratify a new agreement.
The two collective agreements between Newfoundland Power and the International
Brotherhood of Electrical Workers labour union expired on September 30, 2011.
Negotiations to renew the collective agreements began in October 2011.
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 OPEB plans. Additionally, 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 and
nine months ended September 30, 2011, operating expenses increased by
approximately $2 million and $6 million, respectively, 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 continued uncertainty around the
adoption of a rate-regulated accounting standard by the International Accounting
Standards Board, Fortis has evaluated the option of adopting US GAAP, as opposed
to IFRS, and has decided to adopt US GAAP effective January 1, 2012.
Canadian securities rules allow a reporting issuer to prepare and file its
financial statements in accordance with US GAAP by qualifying as an 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 is currently not an SEC Issuer. Therefore, on June 6, 2011, the
Corporation filed an application with the OSC seeking relief, pursuant to
National Policy 11-203 - Process for Exemptive Relief Applications in Multiple
Jurisdictions, to permit the Corporation and its reporting issuer subsidiaries
to prepare their financial statements in accordance with US GAAP without
qualifying as SEC Issuers (the "Exemption"). On June 9, 2011, the OSC issued its
decision and granted the Exemption for financial years commencing on or after
January 1, 2012 but before January 1, 2015, and interim periods therein. The
Exemption will terminate in respect of financial statements for annual and
interim periods commencing on or after the earlier of: (i) January 1, 2015; or
(ii) the date on which the Corporation ceases to have activities subject to rate
regulation.
The Corporation's application of Canadian GAAP currently relies primarily on US
GAAP for guidance on accounting for rate-regulated activities. The adoption of
US GAAP in 2012 is, therefore, 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. US GAAP guidance on
accounting for rate-regulated activities 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, accurately reflects the impact that rate
regulation has on the Corporation's consolidated financial position and results
of operations.
During the fourth quarter of 2010, the Corporation 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: Phase I consisted of project initiation and
awareness; project planning and resourcing; and identification of high-level
differences between US GAAP and Canadian GAAP in order to highlight areas where
detailed analysis would be needed to determine and conclude as to the nature and
extent of financial statement impacts. 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 complete.
Phase II - Analysis and Development: Phase II consists of detailed diagnostics
and evaluation of the financial statement impacts of adopting US GAAP based on
the high-level assessment conducted under Phase I; identification and design of
any new, or changes to, operational or financial business processes; initial
staff training and audit committee orientation; and development of required
solutions to address identified issues.
Phase II had included planned activities for the registration of securities as
required to achieve SEC Issuer status and an assessment of ongoing requirements
of the United States Sarbanes-Oxley Act ("US SOX"), including auditor
attestation of internal controls over financial reporting, and a comparison of
the requirements under US SOX to those required in Canada under National
Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim
Filings. These activities are no longer required or applicable as a result of
the Exemption granted by the OSC as discussed above.
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. In addition, adoption of US GAAP is expected to result in
limited changes in balance sheet classifications, and additional disclosure
requirements. The impact on information systems and internal controls over
financial reporting is expected to be minimal.
Phase III - Implementation and Review: Phase III is currently ongoing and has
involved the implementation of financial reporting systems and internal control
changes required by the Corporation to prepare and file its consolidated
financial statements in accordance with US GAAP beginning in 2012, and the
communication of associated impacts.
The Corporation will prepare and file its audited Canadian GAAP consolidated
financial statements for the year ending December 31, 2011 in the usual manner.
The Corporation then intends to voluntarily prepare and file audited US GAAP
consolidated financial statements for the year ending December 31, 2011, with
2010 comparatives. The Corporation's voluntary filing of audited US GAAP
consolidated financial statements for the year ending December 31, 2011,
subsequent to the filing of its audited Canadian GAAP consolidated financial
statements for the year ending December 31, 2011, has been approved by the OSC
and is expected to be completed by March 31, 2012. Beginning with the first
quarter of 2012, the Corporation's unaudited interim consolidated financial
statements will be prepared and filed in accordance with US GAAP.
Phase III will conclude when the Corporation files its annual audited
consolidated financial statements for the year ending December 31, 2012 prepared
in accordance with US GAAP.
Financial Statement Impacts - US GAAP: The areas identified to date where
differences between US GAAP and Canadian GAAP are expected to have the most
significant financial statement impacts are outlined below. The identified
impacts are unaudited and are subject to change based on further analysis.
Employee future benefits: Under Canadian GAAP, the accrued benefit asset or
liability associated with defined benefit plans is recognized on the balance
sheet with a reconciliation of the recognized asset or liability to the funded
or unfunded status being disclosed in the notes to the consolidated financial
statements. The accrued benefit asset or liability excludes unamortized balances
related to past service costs, actuarial gains and losses and transitional
obligations or assets which have not yet been recognized.
US GAAP requires recognition of the funded or unfunded status of defined benefit
plans on the balance sheet. Unamortized balances related to past service costs,
actuarial gains and losses and transitional obligations are separately
recognized on the balance sheet as a component of accumulated other
comprehensive income or, in the case of entities with activities subject to rate
regulation, as regulatory assets or liabilities for recovery from, or refund to,
customers in future rates. Subsequent changes to past service costs, actuarial
gains and losses and transitional obligations would be recognized as part of
pension expense, where required by the regulator, or otherwise as a change in
the regulatory asset or liability. Therefore, upon adoption of US GAAP, the
Corporation's rate-regulated subsidiaries will recognize the funded or unfunded
status of their defined benefit pension plans on the balance sheet with the
above noted unamortized balances recognized as regulatory assets or liabilities.
US GAAP also requires that OPEB costs be recorded on an accrual basis, and
prohibits the recognition of regulatory assets or liabilities associated with
OPEB costs that are recovered on a cash basis. FortisAlberta has historically
recovered its OPEB costs on a cash basis, as opposed to an accrual basis, and
will likely continue to do so as ordered by its regulator. Therefore,
FortisAlberta's regulatory asset associated with OPEB costs does not meet the
criteria for recognition under US GAAP. Historically, Newfoundland Power had
also recovered its OPEB costs on a cash basis. However, in December 2010, the
regulator 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 associated with the 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 GAAP and
OPEB expense approved by the regulator for rate-setting purposes. The rules
under US GAAP related to accounting for OPEBs by rate-regulated entities require
that Newfoundland Power de-recognize its OPEB regulatory asset as of January 1,
2010 on the premise that, as of that date, Newfoundland Power was recovering its
OPEB costs on a cash basis. However, the regulatory asset will be re-recognized
through earnings in accordance with US GAAP in 2010 based on the regulator's
approval of Newfoundland Power's application to adopt the accrual method of
accounting for OPEBs effective January 1, 2011 and to recover the associated
transitional regulatory asset over a 15-year period.
Additional differences between Canadian GAAP and US GAAP in terms of accounting
for defined benefit plans include the determination of the measurement date and
the attribution period over which pension expense is recognized. Canadian GAAP
allows for the use of a measurement date up to three months prior to the date of
an entity's fiscal year end. However, US GAAP requires the entity's fiscal year
end to be used as the measurement date. Canadian GAAP also allows for the use of
an attribution period for defined benefit pension plans, under specific
circumstances, that extends beyond the date when the credited service period
ends. However, US GAAP allows for the use of an attribution period for defined
benefit pension plans up to the date when credited service ends. The differences
are expected to impact the calculation of the Corporation's consolidated benefit
obligation, which will be mostly offset by a corresponding change to regulatory
assets or liabilities.
With the exception of a one-time adjustment with respect to Newfoundland Power's
inability to recognize its OPEB regulatory asset as of January 1, 2010 and its
ability to subsequently re-recognize this OPEB regulatory asset through earnings
in 2010, the impact of adopting US GAAP with respect to accounting for employee
future benefits, i.e., pensions and OPEBs, is not currently expected to have a
material impact on the Corporation's consolidated earnings.
Brilliant Power Purchase Agreement ("BPPA"): FortisBC Electric expects that its
BPPA will be accounted for as a capital lease under US GAAP. While the
requirement to evaluate whether an arrangement includes a lease is similar
between Canadian GAAP and US GAAP, the effective date for prospective adoption
of lease accounting guidance differs, resulting in an accounting difference with
respect to the BPPA.
Fulfillment of the BPPA is dependent on the use of a specific asset, the
Brilliant Hydroelectric Plant ("Brilliant"), and the conveyance unto FortisBC
Electric the right to use that asset under an arrangement between FortisBC
Electric and the legal owner of Brilliant. The BPPA qualifies as a capital lease
as the present value of the minimum lease payments to be made by FortisBC
Electric represents recovery of the entire amount of the initial investment in
Brilliant by the legal owner over the term of the arrangement.
The anticipated effect of retrospectively recognizing Brilliant as a capital
lease upon adoption of US GAAP includes the recognition on the consolidated
balance sheet of a utility capital asset with an offsetting capital lease
obligation for an equivalent amount. Each subsequent reporting period, the total
amount of amortization and interest expense to be recognized under capital lease
accounting is expected to differ from the amount paid under the BPPA and
recovered through current electricity rates as permitted by the BCUC. This
timing difference is expected to be recognized as a regulatory asset, with
amounts recovered through electricity rates expected to equal the combined
amount of the capitalized lease asset and interest on the lease obligation over
the term of the BPPA.
Since US GAAP allows for entities to account for the effects of rate regulation,
the impact of adopting capital lease accounting for Brilliant is not expected to
affect the Corporation's consolidated earnings.
Reclassification of preference shares: Currently, under Canadian GAAP, the
Corporation's Series C and Series E First Preference Shares are classified as
long-term liabilities with associated dividends classified as finance charges.
Under US GAAP, the Series C and Series E First Preference Shares do not meet the
criteria for recognition as a financial liability. Therefore, upon adoption of
US GAAP, the Corporation will reclassify its Series C and Series E First
Preference Shares from long-term liabilities to shareholders' equity on the
consolidated balance sheet. The associated dividends will not be recorded as
finance charges on the Corporation's consolidated statement of earnings but,
rather, will be recorded as earnings attributable to preference equity
shareholders.
Corporate income taxes: Under Canadian GAAP, the Corporation has calculated and
recognized corporate income taxes using substantively enacted corporate income
tax rates. Under US GAAP, the Corporation is required to calculate and record
corporate income taxes based on enacted corporate income tax rates. Therefore,
upon adoption of US GAAP, the Corporation will be required to recognize the
impact of the difference between enacted tax rates and substantively enacted tax
rates related to the calculation of Part VI.1 tax deductions associated with
preference share dividends. The retroactive adjustment to recognize the Part
VI.1 tax deductions based on enacted corporate income tax rates will result in a
reduction in opening retained earnings under US GAAP and annual earnings
thereafter. However, the adjustments are expected to reverse once pending
Canadian federal legislation is passed and proposed corporate income tax rate
changes become enacted.
The above items do not represent a complete list of expected differences between
US GAAP and Canadian GAAP, and are subject to change. Other less significant
differences have also been identified. Analysis also remains ongoing and
additional areas where the Corporation's consolidated financial statements could
be materially impacted may be identified prior to the Corporation's voluntary
preparation and filing of its audited US GAAP consolidated financial statements
for the year ending December 31, 2011. A detailed reconciliation between the
Corporation's audited Canadian GAAP and US GAAP financial statements for 2011,
including 2010 comparatives, will be disclosed as part of that voluntary filing.
The unaudited, estimated quantification and reconciliation of the Corporation's
consolidated balance sheet as of December 31, 2010 prepared in accordance with
US GAAP versus Canadian GAAP, based on the differences identified to date, may
be summarized as follows.
Total assets as of December 31, 2010 are estimated to increase by approximately
$530 million. The estimated increase is due primarily to expected increases in
regulatory assets and utility capital assets in accordance with US GAAP.
Total liabilities as of December 31, 2010 are estimated to increase by
approximately $260 million. The estimated increase is due primarily to the
expected increases in long-term debt and capital lease obligations and pension
liabilities in accordance with US GAAP, partially offset by the reclassification
of preference shares from liabilities to shareholders' equity.
Shareholders' equity as of December 31, 2010 is estimated to increase by
approximately $270 million. The estimated increase is due primarily to the
expected reclassification of preference shares from liabilities to shareholders'
equity in accordance with US GAAP, partially offset by an estimated reduction in
retained earnings of approximately $35 million based on the retrospective
application of US GAAP. Approximately half of the reduction in retained earnings
results from higher corporate income taxes, as referred to above, and is
expected to reverse in a future period once pending Canadian federal income tax
legislation is passed and proposed Part VI.1 tax rate changes become enacted.
As previously indicated, and subject to the above referenced one-time adjustment
with respect to Newfoundland Power's inability to recognize its OPEB regulatory
asset as of January 1, 2010 and its subsequent ability to re-recognize this OPEB
regulatory asset as of December 31, 2010, no material adjustments to the
Corporation's consolidated earnings are currently expected under US GAAP due to
the Corporation's continued ability to apply rate-regulated accounting policies.
The unaudited, estimated quantification and reconciliation of the Corporation's
consolidated statement of earnings for the year ended December 31, 2010 prepared
in accordance with US GAAP versus Canadian GAAP, based on the differences
identified to date, may be summarized as follows.
Consolidated net earnings to be reported in accordance with US GAAP for the year
ended December 31, 2010, prior to the one-time adjustment to re-recognize
Newfoundland Power's OPEB regulatory asset, are estimated to increase by
approximately $8 million (from $323 million to $331 million). The estimated
increase is due primarily to the expected reclassification of preference share
dividends in accordance with US GAAP from finance charges to earnings
attributable to preference equity shareholders, partially offset by increases in
other finance charges and corporate income taxes, as referred to above, which
are expected to reduce earnings attributable to common equity shareholders by
approximately $9 million.
The one-time, non-recurring adjustment to re-recognize Newfoundland Power's OPEB
regulatory asset as at December 31, 2010 is estimated to increase consolidated
net earnings for the year ended December 31, 2010 by approximately $46 million.
This adjustment is not expected to impact accumulated retained earnings as at
December 31, 2010, as compared to retained earnings reported in accordance with
Canadian GAAP as at December 31, 2010, as it reverses an adjustment made to
derecognize the OPEB regulatory asset upon adoption of US GAAP as at January 1,
2010.
The quantification and reconciliation of the Corporation's consolidated
financial statements from Canadian GAAP to US GAAP for the 2011 annual reporting
period is expected to be completed by March 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 year-to-date 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 December 31, 2009 through September 30, 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.
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Summary of Quarterly Results Net Earnings
Attributable
(Unaudited) to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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September 30, 2011 721 58 0.31 0.31
June 30, 2011 850 58 0.33 0.33
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
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A summary of the past eight quarters reflects the Corporation's continued
organic growth, 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 from June 20, 2011 reflect
the discontinuance of the consolidation method of accounting for Belize
Electricity. For further information, refer to the "Corporate Overview" and
"Business Risk Management - Investment in Belize" sections of this MD&A. Revenue
for the third quarter ended September 30, 2010 reflected the favourable
cumulative retroactive impact associated with the 2010 revenue requirements
decision at FortisAlberta. The commissioning of the Vaca hydroelectric
generating facility in March 2010 has favourably impacted financial results
since that date. 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 of
capital structure for FortisAlberta.
September 2011/September 2010: Net earnings attributable to common equity
shareholders were $58 million, or $0.31 per common share, for the third quarter
of 2011 compared to earnings of $45 million, or $0.26 per common share, for the
third quarter of 2010. A discussion of the variances between the financial
results for the third quarter of 2011 and the third quarter of 2010 is provided
in the "Financial Highlights" section of this MD&A.
June 2011/June 2010: Net earnings attributable to common equity shareholders
were $58 million, or $0.33 per common share, for the second quarter of 2011
compared to earnings of $55 million, or $0.32 per common share, for the second
quarter of 2010. The increase was mainly due to improved performance at the
Canadian Regulated Electric Utilities, driven by rate base growth associated
with utility infrastructure investment at the electric utilities in western
Canada, additional return earned on FortisAlberta's investment in automated
meters, lower market-priced purchased power costs at FortisBC Electric and a
higher allowed ROE at Algoma Power. Results also improved due to lower corporate
business development costs. The above increase in earnings was partially offset
by the unfavourable impact of the timing of spending of certain
regulator-approved increased operating expenses at the FortisBC Energy companies
during 2011, lower non-regulated hydroelectric generation in Belize, and lower
contribution from Fortis Properties reflecting lower occupancies at hotel
operations in western Canada and increased operating expenses. During the second
quarter of 2011, the GOB expropriated the Corporation's investment in Belize
Electricity.
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. The increase was mainly due to improved performance at the
regulated utilities in western Canada, driven by overall rate base growth
associated with utility infrastructure investment, higher energy sales at
FortisBC Electric and FortisAlberta, the timing of recording of the cumulative
impact of FortisAlberta's and FEWI's 2010 revenue requirements decisions and a
$1 million gain on the sale of property at FortisAlberta, partially offset by
the unfavourable impact of the timing of spending of certain regulator-approved
increased operating expenses at the FortisBC Energy companies during 2011.
Earnings also increased due to lower corporate business development costs and
higher non-regulated hydroelectric generation in Belize.
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 rate base growth associated
with utility 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 of Whistler customer
appliances from propane to natural gas, but were favourably impacted by a
one-time $3 million tax adjustment at FortisOntario.
SUBSEQUENT EVENTS
On October 5, 2011, Newfoundland Power received proceeds of approximately $46
million from Bell Aliant upon the closing of the sale of 40% of Newfoundland
Power's joint-use poles.
On October 18, 2011, Fortis Properties acquired the 160-room, full-service
Hilton Suites Winnipeg Airport hotel for an aggregate cash purchase price of
approximately $25 million.
On October 19, 2011, FortisAlberta issued 30-year $125 million 4.54% unsecured
debentures. The proceeds of the debt offering were mainly used to repay
borrowings under the Company's credit facility incurred to finance capital
expenditures, and for general corporate purposes.
OUTLOOK
The Corporation's significant capital expenditure program, which is expected to
be approximately $5.7 billion over the five-year period 2011 through 2015,
should drive growth in earnings and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing
on regulated electric and natural gas utilities in the United States and Canada.
Fortis will also pursue growth in its non-regulated businesses in support of its
regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at November 2, 2011, the Corporation had issued and outstanding approximately
187 million common shares; 5.0 million First Preference Shares, Series C; 8.0
million First Preference Shares, Series E; 5.0 million First Preference Shares,
Series F; 9.2 million First Preference Shares, Series G; and 10.0 million First
Preference Shares, Series H. Only the common shares of the Corporation have
voting rights.
The number of common shares of Fortis that would be issued if all outstanding
stock options, convertible debt and First Preference Shares, Series C and E were
converted as at November 2, 2011 is as follows:
---------------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at November 2, 2011 Number of
Common Shares
Security (millions)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Stock Options 4.8
Convertible Debt 1.4
First Preference Shares, Series C 3.9
First Preference Shares, Series E 6.2
---------------------------------------------------------------------------
Total 16.3
---------------------------------------------------------------------------
---------------------------------------------------------------------------
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 and nine months ended September 30, 2011 and 2010
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30, December 31,
2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 23)
ASSETS
Current assets
Cash and cash equivalents $ 108 $ 109
Assets held for sale (Note 5) 45 -
Accounts receivable (Note 20) 469 655
Prepaid expenses 33 17
Regulatory assets (Note 6) 196 241
Inventories (Note 7) 194 168
Future income taxes 18 14
--------------------------------
1,063 1,204
Assets held for sale (Note 5) - 45
Other assets (Note 8) 284 168
Regulatory assets (Note 6) 945 848
Future income taxes 18 16
Utility capital assets 8,490 8,185
Income producing properties 563 560
Intangible assets 332 324
Goodwill 1,560 1,553
--------------------------------
$ 13,255 $ 12,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 20) $ 242 $ 358
Accounts payable and accrued charges 853 953
Dividends payable 58 54
Income taxes payable 31 30
Regulatory liabilities (Note 6) 50 60
Current installments of long-term debt and
capital lease obligations (Note 9) 91 56
Future income taxes 4 6
--------------------------------
1,329 1,517
Other liabilities 318 308
Regulatory liabilities (Note 6) 512 467
Future income taxes 666 623
Long-term debt and capital lease obligations
(Note 9) 5,504 5,609
Preference shares 320 320
--------------------------------
8,649 8,844
--------------------------------
Shareholders' equity
Common shares (Note 10) 2,973 2,578
Preference shares 592 592
Contributed surplus 13 12
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (Note
12) (60) (94)
Retained earnings 878 804
--------------------------------
4,401 3,897
Non-controlling interests 205 162
--------------------------------
4,606 4,059
--------------------------------
$ 13,255 $ 12,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contingent Liabilities and Commitments (Note 21)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 721 $ 720 $ 2,735 $ 2,627
------------------------------------------------
Expenses
Energy supply costs 246 259 1,207 1,178
Operating 202 196 627 600
Amortization 105 117 311 307
------------------------------------------------
553 572 2,145 2,085
------------------------------------------------
Operating income 168 148 590 542
Finance charges (Note 14) 88 88 271 266
------------------------------------------------
Earnings before corporate
taxes 80 60 319 276
Corporate taxes (Note 15) 12 5 57 48
------------------------------------------------
Net earnings $ 68 $ 55 $ 262 $ 228
------------------------------------------------
------------------------------------------------
Net earnings attributable
to:
Non-controlling interests $ 3 $ 3 $ 7 $ 7
Preference equity
shareholders 7 7 22 21
Common equity shareholders 58 45 233 200
------------------------------------------------
$ 68 $ 55 $ 262 $ 228
------------------------------------------------
------------------------------------------------
Earnings per common share
(Note 10)
Basic $ 0.31 $ 0.26 $ 1.30 $ 1.16
Diluted $ 0.31 $ 0.26 $ 1.29 $ 1.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at beginning of
period $ 874 $ 773 $ 804 $ 763
Net earnings attributable to
common and preference
equity shareholders 65 52 255 221
------------------------------------------------
939 825 1,059 984
Dividends on common shares (54) (48) (159) (193)
Dividends on preference
shares classified as equity (7) (7) (22) (21)
------------------------------------------------
Balance at end of period $ 878 $ 770 $ 878 $ 770
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 68 $ 55 $ 262 $ 228
------------------------------------------------
------------------------------------------------
Other comprehensive income
(loss)
Unrealized foreign currency
translation gains (losses)
on net investments in self-
sustaining foreign
operations 46 (21) 28 (13)
(Losses) gains on hedges of
net investments in self-
sustaining foreign
operations (45) 13 (27) 8
Corporate tax recovery
(expense) 7 (2) 4 (1)
------------------------------------------------
Unrealized foreign currency
translation gains (losses),
net of hedging activities
and tax (Note 12) 8 (10) 5 (6)
------------------------------------------------
Reclassification to earnings
of net losses on derivative
instruments previously
discontinued as cash flow
hedges, net of tax (Note
12) 1 1 1 1
------------------------------------------------
Comprehensive income $ 77 $ 46 $ 268 $ 223
------------------------------------------------
------------------------------------------------
Comprehensive income
attributable to:
Non-controlling interests $ 3 $ 3 $ 7 $ 7
Preference equity
shareholders 7 7 22 21
Common equity shareholders 67 36 239 195
------------------------------------------------
$ 77 $ 46 $ 268 $ 223
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 23) (Note 23)
Operating activities
Net earnings $ 68 $ 55 $ 262 $ 228
Items not affecting cash:
Amortization - utility
capital assets and income
producing properties 94 107 282 276
Amortization - intangible
assets 11 10 31 30
Amortization - other - - (2) 1
Future income taxes 4 - 3 (1)
Other 4 (3) 9 (1)
Change in long-term
regulatory assets and
liabilities (27) (4) (9) (4)
------------------------------------------------
154 165 576 529
Change in non-cash operating
working capital (3) (36) 102 5
------------------------------------------------
151 129 678 534
------------------------------------------------
Investing activities
Change in other assets and
other liabilities - (2) (5) 1
Capital expenditures -
utility capital assets (260) (256) (747) (672)
Capital expenditures -
income producing properties (11) (5) (20) (14)
Capital expenditures -
intangible assets (16) (7) (39) (17)
Contributions in aid of
construction 18 17 49 41
Proceeds on sale of utility
capital assets and income
producing properties - - 6 3
------------------------------------------------
(269) (253) (756) (658)
------------------------------------------------
Financing activities
Change in short-term
borrowings 85 122 (115) (4)
Proceeds from long-term
debt, net of issue costs 9 - 39 -
Repayments of long-term debt
and capital lease
obligations (2) (3) (24) (215)
Net (repayments) borrowings
under committed credit
facilities (178) 36 (105) 193
Advances from non-
controlling interests 20 - 77 1
Issue of common shares, net
of costs and dividends
reinvested 40 4 341 15
Issue of preference shares,
net of costs - - - 242
Dividends
Common shares, net of
dividends reinvested (38) (33) (109) (102)
Preference shares (7) (7) (22) (21)
Subsidiary dividends paid
to non-controlling
interests (2) (2) (6) (6)
------------------------------------------------
(73) 117 76 103
------------------------------------------------
Effect of exchange rate
changes on cash and cash
equivalents 1 - 1 -
------------------------------------------------
Change in cash and cash
equivalents (190) (7) (1) (21)
Cash and cash equivalents,
beginning of period 298 71 109 85
------------------------------------------------
Cash and cash equivalents,
end of period $ 108 $ 64 $ 108 $ 64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
17)
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 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 Caribbean Utilities,
in which Fortis holds an approximate 59% controlling ownership interest;
wholly owned Fortis Turks and Caicos, which includes FortisTCI Limited
(formerly P.P.C. Limited) and Atlantic Equipment & Power (Turks and
Caicos) Ltd.; and Belize Electricity, in which Fortis held an
approximate 70% controlling ownership interest up to June 20, 2011.
Effective June 20, 2011, the Government of Belize enacted legislation
leading to the expropriation of the Corporation's investment in Belize
Electricity and, as a result of no longer exercising control over the
operations of the utility, Fortis discontinued the consolidation method
of accounting for Belize Electricity (Note 8).
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation
assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 22 hotels, including the Hilton Suites
Winnipeg Airport hotel acquired in October 2011, collectively representing 4,300
rooms in eight Canadian provinces, and approximately 2.7 million square feet of
commercial office and retail space primarily in Atlantic Canada
(Note 22).
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 annual 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
OPEB plans. Additionally, 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 and nine months ended September 30, 2011,
operating expenses increased by approximately $2 million and $6 million,
respectively, 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
continued uncertainty around the 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, continues 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 continued uncertainty around the 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, and
has decided to adopt US GAAP effective January 1, 2012. Canadian securities
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 is not currently an SEC Issuer. On June 6, 2011,
the Corporation filed an application with the Ontario Securities Commission (the
"OSC") seeking relief, pursuant to National Policy 11-203 - Process for
Exemptive Relief Applications in Multiple Jurisdictions, to permit the
Corporation and its reporting issuer subsidiaries to prepare their financial
statements in accordance with US GAAP without qualifying as SEC Issuers (the
"Exemption"). On June 9, 2011, the OSC issued its decision and granted the
Exemption for financial years commencing on or after January 1, 2012 but before
January 1, 2015, and interim periods therein. The Exemption will terminate in
respect of financial statements for annual and interim periods commencing on or
after the earlier of: (i) January 1, 2015; or (ii) the date on which the
Corporation ceases to have activities subject to rate regulation.
The Corporation's application of Canadian GAAP currently relies primarily on US
GAAP for guidance on accounting for rate-regulated activities. The adoption of
US GAAP in 2012 is, therefore, 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. US GAAP guidance on
accounting for rate-regulated activities 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, accurately reflects the impact that rate
regulation has on the Corporation's consolidated financial position and results
of operations.
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 and nine months
ended September 30, 2011.
5. ASSETS HELD FOR SALE
On September 28, 2011, the Newfoundland and Labrador Board of Commissioners of
Public Utilities issued an order that approved the sale of 40% of joint-use
poles from Newfoundland Power to Bell Aliant Inc. ("Bell Aliant"). The
Corporation has reclassified assets held for sale of approximately $45 million,
representing the estimated sale price less costs to sell the joint-use poles,
from long-term to current assets on the consolidated balance sheet as at
September 30, 2011. The estimated sale price is subject to adjustment upon
completion of a pole survey later in 2011 (Note 22).
6. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A detailed description of the nature of the Corporation's regulatory
assets and liabilities is provided in Note 5 to the Corporation's 2010 annual
audited consolidated financial statements.
As at
September 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Regulatory assets (Note 23)
Future income taxes 616 568
Rate stabilization accounts - FortisBC
Energy companies 78 146
Rate stabilization accounts - electric
utilities 57 44
Regulatory OPEB plan assets 63 66
Alberta Electric System Operator ("AESO")
charges deferral 53 19
Replacement energy deferral - Point Lepreau
(1) 47 44
Deferred energy management costs 30 23
Deferred losses on disposal of utility
capital assets 21 16
Deferred operating costs 19 11
Income taxes recoverable on OPEB plans 18 18
Capital cost recovery - Whistler pipeline 16 17
Deferred development costs for capital 11 11
2010 accrued distribution revenue adjustment
rider 9 36
Deferred costs - smart meters 9 8
Deferred lease costs 6 6
Deferred pension costs 4 5
Other regulatory assets 84 51
----------------------------------------------------------------------------
Total regulatory assets 1,141 1,089
Less: current portion (196) (241)
----------------------------------------------------------------------------
Long-term regulatory assets 945 848
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)New Brunswick Power Point Lepreau Nuclear Generating Station
As at
September 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Regulatory liabilities
Asset removal and site restoration provision 353 339
Rate stabilization accounts - FortisBC
Energy companies 96 60
Rate stabilization accounts - electric
utilities 33 45
AESO charges deferral 12 9
Deferred interest 10 7
Performance-based rate-setting incentive
liabilities 9 8
Southern Crossing Pipeline deferral 8 5
Unrecognized net gains on disposal of
utility capital assets 6 8
2010 FEI revenue surplus 2 7
Unbilled revenue liability - 5
Other regulatory liabilities 33 34
----------------------------------------------------------------------------
Total regulatory liabilities 562 527
Less: current portion (50) (60)
----------------------------------------------------------------------------
Long-term regulatory liabilities 512 467
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. INVENTORIES
As at
September 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Gas in storage 173 148
Materials and supplies 21 20
----------------------------------------------------------------------------
194 168
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the three and nine months ended September 30, 2011, inventories of $76
million and $590 million, respectively, were expensed and reported in energy
supply costs on the interim consolidated statement of earnings ($90 million and
$586 million for the three and nine months ended September 30, 2010,
respectively). Inventories expensed to operating expenses were $3 million and
$10 million for the three and nine months ended September 30, 2011, respectively
($3 million and $10 million for the three and nine months ended September 30,
2010, respectively). Included in inventories expensed to operating expenses was
food and beverage costs at Fortis Properties of $2 million and $7 million for
the three and nine months ended September 30, 2011, respectively ($2 million and
$7 million for the three and nine months ended September 30, 2010,
respectively).
8. OTHER ASSETS
As at
September 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Deferred pension costs 139 140
Other asset - Belize Electricity 120 -
Long-term accounts receivable 9 9
Other 16 19
----------------------------------------------------------------------------
284 168
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a result of no longer exercising control over the operations of Belize
Electricity, Fortis discontinued the consolidation method of accounting for
Belize Electricity, effective June 20, 2011. The book value of the Corporation's
previously 70% controlled foreign net investment in self-sustaining Belize
Electricity has been classified as a long-term other asset. The asset is
denominated in US dollars and has been translated into Canadian dollars at the
exchange rate prevailing at the balance sheet date. Effective June 20, 2011, the
Corporation's asset associated with its previous investment in Belize
Electricity does not qualify for hedge accounting and, as a result, from June
20, 2011, an approximate $7 million foreign exchange gain on the translation of
the asset was recognized in earnings for the three and nine months ended
September 30, 2011. As at June 20, 2011, approximately $28 million of unrealized
foreign currency translation losses, related to the translation into Canadian
dollars of the Corporation's previous foreign net investment in self-sustaining
Belize Electricity, were reclassified to long-term other assets from accumulated
other comprehensive loss and are included in the $120 million balance as at
September 30, 2011 (Note 12).
9. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at
September 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,522 5,489
Long-term classification of committed credit
facilities (Note 20) 114 218
Deferred debt financing costs (41) (42)
----------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,595 5,665
Less: Current installments of long-term debt
and capital lease obligations (91) (56)
----------------------------------------------------------------------------
5,504 5,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value.
As at
Issued and Outstanding September 30, 2011 December 31, 2010
Number of Number of
Shares Amount Shares Amount
(in
(in thousands)($ millions) thousands)($ millions)
----------------------------------------------------------------------------
Common shares 186,934 2,973 174,393 2,578
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
September 30, 2011 September 30, 2011
Number of Number of
Shares Amount Shares Amount
(in (in
thousands) ($ millions) thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning of
period 185,059 2,915 174,393 2,578
Public offering 1,240 40 10,340 331
Dividend Reinvestment
Plan 529 16 1,498 48
Consumer Share
Purchase Plan 10 - 34 1
Stock Option Plans 96 2 669 15
----------------------------------------------------------------------------
Balance, end of period 186,934 2,973 186,934 2,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In June 2011 Fortis publicly issued 9.1 million common shares for $33.00 per
share. The common share issue resulted in gross proceeds of approximately $300
million, or approximately $291 million net of after-tax expenses. In July 2011
an additional 1.24 million common shares of Fortis were publicly issued for
$33.00 per share, upon the exercise of an over-allotment option, resulting in
gross proceeds of approximately $41 million, or approximately $40 million net of
after-tax expenses.
Earnings per Common Share
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding.
Diluted EPS is calculated using the treasury stock method for options and the
"if-converted" method for convertible securities.
EPS were as follows:
Quarter Ended September 30
2011 2010
----------------------------
Earnings Earnings
to Common Weighted to Common Weighted
Share- Average Share- Average
holders Shares holders Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
---------------------------------------------------------------------------
Basic EPS 58 186.5 $ 0.31 45 173.2 $ 0.26
Effect of
potential
dilutive
securities:
Stock Options - 1.0 - 0.9
Preference
Shares (Note
14) 4 10.1 4 11.9
Convertible
Debentures 1 1.4 1 1.4
---------------------------------------------------------------------------
63 199.0 50 187.4
Deduct anti-
dilutive impacts:
Preference
Shares (4) (10.1) (4) (11.9)
Convertible
Debentures (1) (1.4) (1) (1.4)
---------------------------------------------------------------------------
Diluted EPS 58 187.5 $ 0.31 45 174.1 $ 0.26
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-Date September 30
2011 2010
--------------------------
Earnings Earnings
to Common Weighted to Common Weighted
Share- Average Share- Average
holders Shares holders Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
-------------------------------------------------------------------------
Basic EPS 233 179.5 $ 1.30 200 172.4 $ 1.16
Effect of
potential
dilutive
securities:
Stock Options - 1.0 - 0.9
Preference
Shares (Note
14) 12 10.1 12 11.9
Convertible
Debentures 2 1.4 2 1.4
-------------------------------------------------------------------------
247 192.0 214 186.6
Deduct anti-
dilutive impacts:
Preference
Shares (12) (10.1) - -
-------------------------------------------------------------------------
Diluted EPS 235 181.9 $ 1.29 214 186.6 $ 1.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. 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, upon the death of a Board member, 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 Fortis 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 of Fortis.
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 $4.57 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.68
Expected volatility (%) 23.1
Risk-free interest rate (%) 2.00
Weighted average expected life (years) 4.5
As at September 30, 2011, approximately 4.8 million stock options were
outstanding and approximately 2.7 million stock options were vested.
12. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, and gains and losses on
discontinued cash flow hedging activities as described in Note 3 to the
Corporation's 2010 annual audited consolidated financial statements.
Quarter Ended September 30
2011 2010
-------------------------------------------------------------
Ending Ending
Opening balance Opening balance
balance Net September balance Net September
($ millions) July 1 change 30 July 1 change 30
----------------------------------------------------------------------------
Unrealized
foreign
currency
translation
(losses)
gains, net of
hedging
activities and
tax (65) 8 (57) (74) (10) (84)
Net losses on
derivative
instruments
previously
discontinued
as cash flow
hedges, net of
tax (4) 1 (3) (5) 1 (4)
----------------------------------------------------------------------------
Accumulated
other
comprehensive
(loss) income (69) 9 (60) (79) (9) (88)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date September 30
2011 2010
-------------------------------------------------------------
Ending Ending
Opening balance Opening balance
($ millions) balance Net September balance Net September
January 1 change 30 January 1 change 30
----------------------------------------------------------------------------
Unrealized
foreign
currency
translation
(losses)
gains, net of
hedging
activities and
tax (90) 33 (57) (78) (6) (84)
Net losses on
derivative
instruments
previously
discontinued
as cash flow
hedges, net of
tax (4) 1 (3) (5) 1 (4)
----------------------------------------------------------------------------
Accumulated
other
comprehensive
(loss) income (94) 34 (60) (83) (5) (88)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net change in accumulated other comprehensive loss for the nine months ended
September 30, 2011 includes the reclassification of approximately $28 million of
unrealized foreign currency translation losses, related to the translation into
Canadian dollars of the Corporation's previous foreign net investment in
self-sustaining Belize Electricity, to long-term other assets from accumulated
other comprehensive loss as at June 20, 2011 (Note 8). As at September 30, 2011,
unrealized after-tax foreign currency translation gains of approximately $11
million related to corporately issued US dollar borrowings previously designated
as an effective hedge of the Corporation's previous foreign net investment in
self-sustaining Belize Electricity, remained in accumulated other comprehensive
loss.
13. 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 $16 million for the
quarter ended September 30, 2011 ($10 million for the quarter ended September
30, 2010) and $46 million year-to-date September 30, 2011 ($28 million
year-to-date September 30, 2010). The cost of providing the defined contribution
arrangements and group RRSPs for the quarter ended September 30, 2011 was $3
million ($3 million for the quarter ended September 30, 2010) and $11 million
year-to-date September 30, 2011 ($10 million year-to-date September 30, 2010).
14. FINANCE CHARGES
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Interest
- Long-term debt and capital lease
obligations 91 89 270 265
- Short-term borrowings and other 1 3 10 6
Allowance for funds used during
construction (6) (8) (19) (17)
Unrealized net foreign exchange gain (1) (2) - (2) -
Dividends on preference shares
classified as debt (Note 10) 4 4 12 12
----------------------------------------------------------------------------
88 88 271 266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Comprised of a $7 million foreign exchange gain on the translation into
Canadian dollars of the Corporation's long-term asset associated with Belize
Electricity (Note 8), partially offset by a $5.5 million foreign exchange
loss on the translation into Canadian dollars of the Corporation's unhedged
US dollar borrowings.
15. CORPORATE TAXES
Corporate taxes differ from the amount that would be expected to be generated by
applying the enacted combined Canadian federal and provincial statutory tax rate
to earnings before corporate taxes. The following is a reconciliation of
consolidated statutory taxes to consolidated effective taxes.
Quarter Ended Year-to-Date
September 30 September 30
($ millions, except as
noted) 2011 2010 2011 2010
----------------------------------------------------------------------------
Combined Canadian federal
and provincial statutory
income tax rate 30.5% 32.0% 30.5% 32.0%
----------------------------------------------------------------------------
Statutory income tax rate
applied to earnings before
corporate taxes 24 20 97 89
Preference share dividends 1 1 4 4
Difference between Canadian
statutory rate and rates
applicable to foreign
subsidiaries (1) (5) (9) (12)
Difference in Canadian
provincial statutory rates
applicable to subsidiaries
in different Canadian
jurisdictions (4) (2) (9) (8)
Items capitalized for
accounting purposes but
expensed for income tax
purposes (11) (9) (39) (29)
Difference between capital
cost allowance and amounts
claimed for accounting
purposes 5 (2) 11 (1)
Other (2) 2 2 5
----------------------------------------------------------------------------
Corporate taxes 12 5 57 48
----------------------------------------------------------------------------
Effective tax rate 15.0% 8.3% 17.9% 17.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2011, the Corporation had approximately $62 million
(December 31, 2010 - $95 million) in non-capital and capital loss carryforwards,
of which $18 million (December 31, 2010 - $18 million) has not been recognized
in the consolidated financial statements. The non-capital loss carryforwards
expire between 2014 and 2031.
16. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
----------------------------------------------------------------
Gas
Utilities Electric Utilities
----------------------------------------------------------------
Fortis
BC
Quarter Energy Total Elec-
Ended Compa- Fortis Elec- tric
September nies - BC Newfound- Other tric (1)
30, 2011 Cana- Fortis Elec- land Cana- Cana- Carib-
($ millions) dian Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 198 103 67 101 88 359 73
Energy
supply
costs 76 - 15 52 56 123 47
Operating
expenses 68 35 19 17 12 83 8
Amorti-
zation 28 34 11 11 6 62 7
----------------------------------------------------------------------------
Operating
income 26 34 22 21 14 91 11
Finance
charges 32 15 10 9 5 39 2
Corporate
tax
(recovery)
expense (3) - 2 4 3 9 -
----------------------------------------------------------------------------
Net (loss)
earnings (3) 19 10 8 6 43 9
Non-
controlling
interests - - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attri-
butable to
common
equity
share-
holders (3) 19 10 8 6 43 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,219 2,341 1,300 1,211 659 5,511 752
----------------------------------------------------------------------------
Total assets 5,127 2,568 1,521 1,211 722 6,022 893
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 65 82 25 24 14 145 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter
Ended
September
30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 206 109 62 99 87 357 92
Energy
supply
costs 90 - 16 50 57 123 57
Operating
expenses 66 33 17 16 11 77 12
Amorti-
zation 27 45 10 12 6 73 9
----------------------------------------------------------------------------
Operating
income 23 31 19 21 13 84 14
Finance
charges 28 12 7 9 5 33 4
Corporate
tax expense
(recovery) - - 1 4 3 8 (1)
----------------------------------------------------------------------------
Net (loss)
earnings (5) 19 11 8 5 43 11
Non-
controlling
interests - - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attri-
butable to
common
equity
share-
holders (5) 19 11 8 5 43 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable
assets 4,168 2,069 1,220 1,182 631 5,102 805
----------------------------------------------------------------------------
Total assets 5,076 2,296 1,441 1,182 694 5,613 943
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 72 102 36 20 12 170 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
----------------------------------
Quarter
Ended
September Inter-
30, 2011 Fortis(2) FortisCorporate(3) segment
($ millions) GenerationProperties and Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 11 63 25 (8) 721
Energy
supply
costs - - - - 246
Operating
expenses 2 40 3 (2) 202
Amorti-
zation 1 5 2 - 105
----------------------------------------------------------------------------
Operating
income 8 18 20 (6) 168
Finance
charges - 6 15 (6) 88
Corporate
tax
(recovery)
expense - 3 3 - 12
----------------------------------------------------------------------------
Net (loss)
earnings 8 9 2 - 68
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 7 - 7
----------------------------------------------------------------------------
Net (loss)
earnings
attri-
butable to
common
equity
share-
holders 8 9 (5) - 58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,560
Identifiable
assets 519 588 517 (411) 11,695
----------------------------------------------------------------------------
Total assets 519 588 517 (411) 13,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 49 11 - - 287
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter
Ended
September
30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 13 60 8 (16) 720
Energy
supply
costs - - - (11) 259
Operating
expenses 2 38 3 (2) 196
Amorti-
zation 2 5 1 - 117
----------------------------------------------------------------------------
Operating
income 9 17 4 (3) 148
Finance
charges - 6 20 (3) 88
Corporate
tax expense
(recovery) - 2 (4) - 5
----------------------------------------------------------------------------
Net (loss)
earnings 9 9 (12) - 55
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 7 - 7
----------------------------------------------------------------------------
Net (loss)
earnings
attri-
butable to
common
equity
share-
holders 9 9 (19) - 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable
assets 193 580 526 (423) 10,951
----------------------------------------------------------------------------
Total assets 193 580 526 (423) 12,508
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 4 5 - - 268
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Reflects the discontinuance of the consolidation method of accounting
for Belize Electricity from June 20, 2011 (Note 8)
(2) Results reflect contribution from the Vaca hydroelectric generating
facility in Belize, which was commissioned in March 2010, and the Waneta
Expansion Limited Partnership ("Waneta Partnership"), which was established
in October 2010.
(3) Results reflect the $11 million after-tax fee paid to Fortis in July
2011 following upon the termination of the Merger Agreement between Fortis
and Central Vermont Public Service Corporation ("CVPS").
(4) Relates to cash payments to acquire or construct utility capital assets,
including amounts for AESO transmission-related capital projects, income
producing properties and intangible assets, as reflected on the consolidated
statement of cash flows
REGULATED
----------------------------------------------------------------
Gas
Utilities Electric Utilities
----------------------------------------------------------------
Fortis
BC Energy Total Elec-
Year-to-Date Compa- Fortis Elec- tric
September nies - BC Newfound- Other tric (1)
30, 2011 Cana- Fortis Elec- land Cana- Cana- Carib-
($ millions) dian Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 1,093 310 215 417 256 1,198 236
Energy
supply
costs 590 - 49 266 163 478 146
Operating
expenses 219 106 58 54 34 252 31
Amorti-
zation 81 100 34 32 18 184 24
----------------------------------------------------------------------------
Operating
income 203 104 74 65 41 284 35
Finance
charges 91 44 28 27 16 115 11
Corporate
tax expense
(recovery) 24 1 8 12 7 28 1
----------------------------------------------------------------------------
Net earnings
(loss) 88 59 38 26 18 141 23
Non-
controlling
interests - - - - - - 7
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attri-
butable to
common
equity
share-
holders 88 59 38 26 18 141 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,219 2,341 1,300 1,211 659 5,511 752
----------------------------------------------------------------------------
Total assets 5,127 2,568 1,521 1,211 722 6,022 893
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 179 253 78 55 33 419 57
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
September
30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 1,067 289 193 403 244 1,129 251
Energy
supply
costs 586 - 50 256 156 462 149
Operating
expenses 201 104 53 47 33 237 35
Amorti-
zation 81 94 31 35 18 178 27
----------------------------------------------------------------------------
Operating
income 199 91 59 65 37 252 40
Finance
charges 84 40 23 27 16 106 13
Corporate
tax expense
(recovery) 30 - 3 12 7 22 1
----------------------------------------------------------------------------
Net earnings
(loss) 85 51 33 26 14 124 26
Non-
controlling
interests - - - - - - 7
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attri-
butable to
common
equity
share-
holders 85 51 33 26 14 124 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable
assets 4,168 2,069 1,220 1,182 631 5,102 805
----------------------------------------------------------------------------
Total assets 5,076 2,296 1,441 1,182 694 5,613 943
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 182 258 99 56 33 446 53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
----------------------------------
Year-to-Date Fortis
September (2) Inter-
30, 2011 Genera- FortisCorporate(3) segment
($ millions) tionProperties and Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 25 173 40 (30) 2,735
Energy
supply
costs 1 - - (8) 1,207
Operating
expenses 6 117 7 (5) 627
Amorti-
zation 3 14 5 - 311
----------------------------------------------------------------------------
Operating
income 15 42 28 (17) 590
Finance
charges 1 18 52 (17) 271
Corporate
tax expense
(recovery) 1 6 (3) - 57
----------------------------------------------------------------------------
Net earnings
(loss) 13 18 (21) - 262
Non-
controlling
interests - - - - 7
Preference
share
dividends - - 22 - 22
----------------------------------------------------------------------------
Net earnings
(loss)
attri-
butable to
common
equity
share-
holders 13 18 (43) - 233
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,560
Identifiable
assets 519 588 517 (411) 11,695
----------------------------------------------------------------------------
Total assets 519 588 517 (411) 13,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 131 20 - - 806
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
September
30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 26 169 23 (38) 2,627
Energy
supply
costs 1 - - (20) 1,178
Operating
expenses 6 113 13 (5) 600
Amorti-
zation 3 13 5 - 307
----------------------------------------------------------------------------
Operating
income 16 43 5 (13) 542
Finance
charges - 18 58 (13) 266
Corporate
tax expense
(recovery) 2 6 (13) - 48
----------------------------------------------------------------------------
Net earnings
(loss) 14 19 (40) - 228
Non-
controlling
interests - - - - 7
Preference
share
dividends - - 21 - 21
----------------------------------------------------------------------------
Net earnings
(loss)
attri-
butable to
common
equity
share-
holders 14 19 (61) - 200
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable
assets 193 580 526 (423) 10,951
----------------------------------------------------------------------------
Total assets 193 580 526 (423) 12,508
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (4) 7 14 1 - 703
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Reflects the discontinuance of the consolidation method of accounting
for Belize Electricity from June 20, 2011 (Note 8)
(2) 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.
(3) Results reflect the $11 million after-tax fee paid to Fortis in July
2011 following upon the termination of the Merger Agreement between Fortis
and CVPS.
(4) Relates to cash payments to acquire or construct utility capital assets,
including amounts for AESO transmission-related capital projects, income
producing properties and intangible assets, as reflected on the consolidated
statement of cash flows
Inter-segment transactions are in the normal course of operations and are
measured at the exchange amount, which is the amount of consideration
established and agreed to by the related parties. The significant inter-segment
transactions primarily related to: (i) the sale of energy from Fortis Generation
to Belize Electricity, up to June 20, 2011, and to FortisOntario; (ii)
electricity sales from Newfoundland Power to Fortis Properties; and (iii)
finance charges on inter-segment borrowings. The significant inter-segment
transactions for the three and nine months ended September 30, 2011 and 2010
were as follows:
Significant Inter-Segment
Transactions Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities -
Caribbean - 11 7 19
Sales from Fortis Generation to
Other Canadian Electric
Utilities - - 1 1
Sales from Newfoundland Power to
Fortis Properties 1 1 3 3
Inter-segment finance charges on
borrowings from:
Corporate to Regulated
Electric Utilities - Canadian 1 - 2 -
Corporate to Regulated
Electric Utilities -
Caribbean 1 - 3 2
Corporate to Fortis Generation 1 1 2 3
Corporate to Fortis Properties 3 2 9 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at September 30
($ millions) 2011 2010
----------------------------------------------------------------------------
Inter-segment borrowings from:
Corporate to Regulated Electric Utilities -
Canadian 50 75
Corporate to Regulated Electric Utilities -
Caribbean 78 57
Corporate to Fortis Generation 50 55
Corporate to Fortis Properties 226 223
Other inter-segment assets 7 13
----------------------------------------------------------------------------
Total inter-segment eliminations 411 423
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2011 2010 2011 2010
----------------------------------------------------------------------------
Interest paid 79 83 260 261
Income taxes paid 16 8 61 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
18. 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 support utility infrastructure investment, 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
September 30, 2011 December 31, 2010
($ millions) (%) ($ millions) (%)
----------------------------------------------------------------------------
Total debt and capital
lease obligations (net of
cash) (1) 5,729 54.8 5,914 58.4
Preference shares (2) 912 8.7 912 9.0
Common shareholders'
equity 3,809 36.5 3,305 32.6
----------------------------------------------------------------------------
Total (3) 10,450 100.0 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 September 30, 2011, the Corporation and its subsidiaries, except for the
Exploits River Hydro Partnership ("Exploits Partnership"), as described below,
were in compliance with their debt covenants.
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 $56 million as at September 30,
2011 (December 31, 2010 - $58 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan are
being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to expropriation matters.
For further information refer to Note 30 to the Corporation's 2010 annual
audited consolidated financial statements.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 20.
19. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the nine months ended September 30, 2011 in the
designation of the Corporation's financial instruments from that disclosed in
the Corporation's 2010 annual audited consolidated financial statements.
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as noted in the
following table.
As at
September 30, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value ValueFair Value
----------------------------------------------------------------------------
Waneta Partnership promissory
note (1) (2) 44 47 42 40
Long-term debt, including current
portion (3) (4) 5,595 6,728 5,669 6,431
Preference shares, classified as
debt (3) (5) 320 345 320 344
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in long-term 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 September 30, 2011 excludes unamortized deferred
financing costs of $41 million (December 31, 2010 - $42 million) and capital
lease obligations of $41 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 $616 million as at
September 30, 2011 (December 31, 2010 - $615 million).
Excluded from the above table is the $120 million long-term other asset as at
September 30, 2011 related to the Corporation's previous investment in Belize
Electricity. The fair value of this financial asset is not determinable at this
time.
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Partnership promissory note, the fair value is determined by discounting
the future cash flows of the specific debt instrument at an estimated yield to
maturity equivalent to benchmark government bonds or treasury bills, with
similar terms to maturity, plus a market credit risk premium equal to that of
issuers of similar credit quality. Since the Corporation does not intend to
settle the long-term debt or promissory note prior to maturity, the fair value
estimate does not represent an actual liability and, therefore, does not include
exchange or settlement costs. The fair value of the Corporation's preference
shares is determined using quoted market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes. The following table summarizes the valuation of the
Corporation's consolidated derivative financial instruments.
As at
September 30, 2011 December 31, 2010
Estimated
Carrying Fair Carrying Estimated
Term to Number Value Value Value Fair Value
Maturity of ($ ($ ($ ($
Liability (years) Contracts millions) millions) millions) millions)
----------------------------------------------------------------------------
Foreign
exchange
forward
contract less
(1) than 1 1 - - - -
Fuel option
contracts less
(1) (2) than 1 2 (1) (1) - -
Natural gas
derivatives
: (1) (2)
Swaps and
options Up to 3 201 (101) (101) (162) (162)
Gas
purchase
contract
premiums Up to 2 85 (3) (3) (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 derivatives were recorded in accounts payable as
at September 30, 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.
20. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit Risk Risk that a third party to a financial instrument might fail
to meet its obligations under the terms of the financial
instrument.
Liquidity Risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market Risk Risk that the fair value or future cash flows of a financial
instrument will fluctuate due to changes in market prices.
The Corporation is exposed to 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 September
30, 2011, the utility's gross credit risk exposure was approximately $140
million, representing the projected value of retailer billings over a 60-day
period. The Company has reduced its exposure to approximately $6 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 $16 million as at
September 30, 2011 (June 30, 2011 - $16 million; March 31, 2011 - $18 million;
December 31, 2010 - $16 million; September 30, 2010 - $17 million) was as
follows:
September December September
30, June 30, March 31, 31, 30,
($ millions) 2011 2011 2011 2010 2010
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Not past due 396 488 601 584 399
Past due 0-30 days 46 67 76 56 29
Past due 31-60 days 14 20 15 9 9
Past due 61 days and
over 13 14 8 6 6
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469 589 700 655 443
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Effective June 30, 2011, the aging analysis includes amounts owed to Belize
Electric Company Limited ("BECOL") from Belize Electricity, due to the
discontinuance of the consolidation method of accounting for Belize Electricity.
As at September 30, 2011, long-term other receivables of $14 million (included
in long-term other assets) will be received over the next five years and
thereafter, with $3 million expected to be received over years 2 and 3, $1
million over years 4 and 5 and $10 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
the capital and bank credit markets, ratings assigned by rating agencies and
general economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing
of acquisitions and for general corporate purposes. Depending on the timing of
cash payments from the subsidiaries, borrowings under the Corporation's
committed credit facility may be required from time to time to support the
servicing of debt and payment of dividends. As at September 30, 2011, average
annual consolidated long-term debt maturities and repayments over the next five
years are expected to be approximately $270 million. The combination of
available credit facilities and relatively low annual debt maturities and
repayments provide the Corporation and its subsidiaries with flexibility in the
timing of access to capital markets.
As at September 30, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.3 billion, of which $1.9 billion was
unused. The credit facilities are syndicated mostly with the seven largest
Canadian banks, with no one bank holding more than 20% of these facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
September December
($ millions) Corporate Regulated Fortis 30, 31,
and Other Utilities Properties 2011 2010
---------------------------------------------------------------------------
Total credit
facilities 845 1,490 13 2,348 2,109
Credit
facilities
utilized:
Short-term
borrowings - (239) (3) (242) (358)
Long-term
debt (Note
9) (1) - (114) - (114) (218)
Letters of
credit
outstanding (1) (65) - (66) (124)
---------------------------------------------------------------------------
Credit
facilities
unused 844 1,072 10 1,926 1,409
---------------------------------------------------------------------------
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(1) As at September 30, 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 September 30, 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 renegotiated and amended its 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.
In April 2011 FHI extended the maturity date of its $30 million unsecured
committed revolving credit facility to May 2012.
In June 2011 Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility obtaining an extension to the maturity of
the facility to August 2015 from August 2013. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
In August 2011 the Corporation renegotiated and amended its unsecured committed
revolving credit facility, increasing the amount available under the facility to
$800 million from $600 million and extending the maturity date of the facility
to July 2015 from May 2012. At any time prior to maturity, the Corporation may
provide written notice to increase the amount available under the facility to $1
billion. The amended credit facility agreement reflects an increase in pricing
but, otherwise, contains substantially similar terms and conditions as the
previous credit facility agreement.
In September 2011 FortisAlberta amended its unsecured committed revolving credit
facility to increase the amount available under the facility to $250 million
from $200 million and extend the maturity date to September 2015 from May 2012.
The amended credit facility agreement reflects an increase in pricing.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
September 30, 2011, the Corporation's credit ratings were as follows:
Standard & Poor's A- (long-term corporate and unsecured debt credit rating)
DBRS A(low) (unsecured debt credit rating)
During the third quarter of 2011, DBRS confirmed the Corporation's existing debt
credit rating at A(low). The credit ratings reflect the Corporation's low
business-risk profile and diversity of its operations, the stand-alone nature
and financial separation of each of the regulated subsidiaries of Fortis,
management's commitment to maintaining low levels of debt at the holding company
level, the Corporation's reasonable credit metrics and its demonstrated ability
and continued focus on acquiring and integrating stable regulated utility
businesses financed on a conservative basis.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at September 30, 2011.
Financial Liabilities Due Due in Due in Due
within 1 years 2 years 4 after 5
($ millions) year and 3 and 5 years Total
----------------------------------------------------------------------------
Short-term borrowings 242 - - - 242
Trade and other
accounts payable 748 - - - 748
Natural gas
derivatives (1) 63 27 1 - 91
Fuel option contracts
(2) 1 - - - 1
Foreign exchange
forward contract (3) 5 - - - 5
Dividends payable 58 - - - 58
Customer deposits (4) - 3 1 2 6
Waneta Partnership
promissory note (5) - - - 72 72
Long-term debt,
including current
portion (6) 88 439 817 4,251 5,595
Interest obligations
on long-term debt 346 677 588 4,886 6,497
Preference shares,
classified as debt - 123 197 - 320
Dividend obligations
on preference
shares,
classified as finance
charges 17 26 20 - 63
----------------------------------------------------------------------------
1,568 1,295 1,624 9,211 13,698
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts disclosed are on a gross cash flow basis. The derivatives were
recorded in accounts payable at fair value as at September 30, 2011 at
$104 million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts payable at fair value as at September 30, 2011 at
$1 million.
(3) Amounts disclosed are on a gross cash flow basis. The contract was
recorded in accounts receivable at fair value as at September 30, 2011
at less than $1 million.
(4) Customer deposits were recorded in long-term other liabilities as at
September 30, 2011.
(5) Amounts disclosed are on a gross cash flow basis. The promissory note
was recorded in long-term other liabilities at present value as at
September 30, 2011 at $44 million.
(6) Excludes deferred debt financing costs of $41 million and capital
lease obligations of $41 million
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investments 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. Foreign exchange
gains and losses on the translation of US dollar-denominated interest expense
partially offsets the foreign exchange losses and gains on the translation of
the Corporation's foreign subsidiaries' earnings, which are denominated in US
dollars. The reporting currency of Caribbean Utilities, Fortis Turks and Caicos,
FortisUS Energy Corporation and BECOL is the US dollar.
As at September 30, 2011, US$550 million of the US$590 million corporately
issued long-term debt (December 31, 2010 - US$590 million of US$590 million) had
been designated as an effective hedge of the Corporation's net investments in
self-sustaining foreign subsidiaries. Foreign currency exchange rate
fluctuations associated with the translation of the Corporation's corporately
issued US dollar borrowings designated as effective hedges are recognized in
other comprehensive income and help offset unrealized foreign currency exchange
gains and losses on the net investments in self-sustaining foreign subsidiaries,
which are also recognized in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with its previous
investment in Belize Electricity (Note 8) does not qualify for hedge accounting
as Belize Electricity is no longer a self-sustaining foreign subsidiary of
Fortis. As a result, as at September 30, 2011, approximately US$40 million of
corporately issued debt that previously hedged the former investment in Belize
Electricity is no longer an effective hedge. Effective from June 20, 2011,
foreign exchange gains and losses on the translation of the asset associated
with Belize Electricity and the corporately issued US dollar denominated debt
that previously qualified as a hedge of the investment are required to be
recognized in earnings. As a result, the Corporation recognized a net after-tax
foreign exchange gain of approximately $2.5 million in earnings during the
quarter ended September 30, 2011. As at September 30, 2011, all of the
Corporation's net investments in self-sustaining foreign subsidiaries were
hedged (December 31, 2010 - 99%).
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
("LNG") storage facility, respectively, have exposed the utilities to
fluctuations in the US dollar-to-Canadian dollar exchange rate. FEI and FEVI had
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. During the third quarter of 2011, FEVI's foreign
exchange forward contract related to payments required in US dollars associated
with the construction of the LNG storage facility matured.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk
associated with credit facility 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 from
time to time 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, to temper gas
price volatility on customer rates and reduce the risk of regional price
discrepancies. In January 2011 FEI filed a report of its review to its Price
Risk Management Plan ("PRMP") objectives with the British Columbia Utilities
Commission ("BCUC") related to its gas commodity hedging plan and also submitted
a revised 2011-2014 PRMP. In July 2011 the BCUC issued its decision on FEI's
report and determined that commodity hedging in the current environment was not
a cost effective means of meeting the objectives of price competitiveness and
rate stability. The BCUC concurrently denied FEI's 2011-2014 PRMP with the
exception of certain elements to address regional price discrepancies. As a
result, FEVI and FEI have suspended commodity-hedging activities with the
exception of limited swaps as permitted by the BCUC. The existing hedging
contracts are expected to continue in effect through to their maturity and the
gas utilities' ability to fully recover the commodity cost of gas in customer
rates remains unchanged.
Caribbean Utilities is exposed to commodity price risk associated with changes
in the market price of fuel. The Company has a Fuel Price Volatility Management
Program, as approved by the regulator, to reduce the impact of volatility of
fuel prices on customer rates. The 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. In April 2011 Caribbean
Utilities entered into two fuel option contracts.
21. 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.
As a result of Belize Electricity no longer being consolidated in the
Corporation's financial statements effective June 20, 2011, the power purchase
obligations associated with Belize Electricity's operations are no longer
included in the Corporation's consolidated commitments.
During the first half of 2011, the actuarial valuation of the defined benefit
pension plans at the FortisBC Energy companies, covering unionized employees,
and at FortisBC Electric were completed. As a result of the actuarial valuations
and other revised actuarial estimates, the total estimate of consolidated
defined benefit pension funding contributions over the next five years, net of
payments made year-to-date September 30, 2011, has increased by approximately
$34 million from that disclosed in the Corporation's 2010 annual audited
consolidated financial statements. The increase in funding contributions is
expected to be recovered from customers in future rates.
22. SUBSEQUENT EVENTS
On October 5, 2011, Newfoundland Power received proceeds of approximately $46
million from Bell Aliant upon the closing of the sale of 40% of Newfoundland
Power's joint-use poles (Note 5).
On October 18, 2011, Fortis Properties acquired the 160-room, full-service
Hilton Suites Winnipeg Airport hotel for an aggregate cash purchase price of
approximately $25 million.
On October 19, 2011, FortisAlberta issued 30-year $125 million 4.54% unsecured
debentures. The proceeds of the debt offering were mainly used to repay
borrowings under the Company's credit facility incurred to finance capital
expenditures, and for general corporate purposes.
23. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
presentation. The most significant changes related to: (i) a $48 million
decrease for the nine months ended September 30, 2010 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; (ii) a $15 million and $43 million decrease for the
three and nine months ended September 30, 2010, respectively, in cash from
financing activities associated with the issuance of common shares and a
corresponding decrease in cash used in financing activities associated with
dividends paid on common shares; and (iii) a $17 million increase in long-term
regulatory assets and a corresponding $17 million decrease in utility capital
assets associated with a change in presentation at the FortisBC Energy
companies.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with
total assets of more than $13 billion and fiscal 2010 revenue totalling
approximately $3.7 billion. The Corporation serves more than 2,000,000 gas and
electricity customers. Its regulated holdings include electric distribution
utilities in five Canadian provinces and two 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 in 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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