Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter
net earnings attributable to common equity shareholders of $58 million, or $0.33
per common share, compared to $55 million, or $0.32 per common share, for the
second quarter of 2010. Net earnings attributable to common equity shareholders
for the first half of 2011 were $175 million, or $1.00 per common share, up $20
million from earnings of $155 million, or $0.90 per common share, for the first
half of last year.
Canadian Regulated Electric Utilities contributed earnings of $45 million, up $5
million from the second quarter of 2010. The increase reflected improved results
at the electric utilities in western Canada associated with overall growth in
utility infrastructure investment, lower market-priced purchased power costs at
FortisBC Electric and additional return earned on FortisAlberta's investment in
automated meters.
Canadian Regulated Gas Utilities contributed earnings of $15 million compared to
$17 million for the second quarter of 2010. The decrease in earnings was mainly
attributable to the timing of operating expenses, partially offset by the impact
of growth in utility infrastructure investment and higher gas delivery volumes
in the forestry sector. Due to the seasonality of the business, most of the
earnings of the gas utilities are realized in the first and fourth quarters.
The average monthly run rate for the Corporation's 2011 capital program is
approximately $100 million, more than 80% of which is being driven by the
regulated utilities in western Canada and the Corporation's non-regulated Waneta
hydroelectric generation expansion project in British Columbia (the "Waneta
Expansion Project"), in which Fortis holds a 51% controlling interest. Gross
capital expenditures for the first half of 2011 totalled $519 million. Several
capital projects which commenced prior to 2011 are being completed this year.
During the second quarter FortisBC's gas business substantially completed
construction of its liquefied natural gas ("LNG") storage facility on Vancouver
Island at an estimated cost of $214 million. The LNG storage facility is
currently being filled and is expected to be available for the upcoming winter
heating season. FortisBC's electricity business expects to substantially
complete its $105 million Okanagan Transmission Reinforcement Project later this
year. FortisAlberta has substantially completed its $126 million Automated
Metering Project, which involved the replacement of approximately 466,000
conventional meters. Work continues on the $900 million Waneta Expansion
Project, which is expected to be completed in spring 2015.
With regard to regulatory matters, FortisBC recently filed two-year (2012-2013)
rate applications for both its gas and electricity businesses. Earlier in the
year, FortisAlberta filed a two-year (2012-2013) rate application, including
proposed gross capital expenditures of more than $775 million over the two-year
period.
Caribbean Regulated Electric Utilities contributed $7 million, consistent with
earnings for the second quarter of 2010. Energy sales at Caribbean Utilities and
Fortis Turks and Caicos continue to be impacted by the persistent challenging
economic conditions being experienced in the region. Effective June 20, 2011,
the Government of Belize (the "GOB") expropriated the Corporation's investment
in Belize Electricity. Consequently, there will be no future earnings
contribution to Fortis from Belize Electricity. Belize Electricity has
contributed minimal earnings since mid-2008. In late July, Fortis, as part of
its legal approach, initiated proceedings for compensation from the GOB for the
value of the Corporation's previous investment in Belize Electricity. To date,
the Corporation's non-regulated hydroelectric generating business in Belize,
Belize Electric Company Limited ("BECOL"), has not been impacted by the GOB
legislation.
Fortis Properties delivered earnings of $7 million compared to $8 million for
the second quarter of 2010, reflecting lower occupancies at hotel operations in
western Canada, combined with increased operating expenses.
Non-Regulated Fortis Generation contributed $2 million to earnings compared to
$3 million for the second quarter of 2010. Results mainly reflected decreased
production at BECOL due to lower rainfall.
Corporate and other expenses were $18 million, $2 million lower quarter over
quarter, mainly due to reduced operating expenses. Higher operating expenses
incurred in the second quarter of 2010 related to business development costs.
Cash flow from operating activities was $527 million for the first half of 2011,
up $122 million from the first half of 2010, driven by higher earnings, the
collection from customers of higher amortization costs and favourable changes in
working capital and regulatory deferral accounts.
The Merger Agreement between Fortis and Central Vermont Public Service
Corporation ("CVPS") announced on May 30, 2011 (the "Merger Agreement") was
terminated in July, subsequent to quarter end. Pursuant to the terms of the
Merger Agreement, CVPS paid Fortis a US$17.5 million termination fee plus US$2
million for expenses.
Fortis recently raised total gross proceeds of approximately $341 million from
the public issuance of 9,100,000 common shares in June, and an additional
1,240,000 common shares in July upon the exercise of an over-allotment option by
the underwriters. Net proceeds of the equity issue are being used to repay
borrowings under credit facilities and finance equity injections into the
utilities in western Canada and the Waneta Expansion Limited Partnership in
support of infrastructure investment, and for general corporate purposes.
"We are on track to complete our $1.2 billion 2011 capital expenditure program,"
says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "Our
five-year capital expenditure program out to the end of 2015 is forecasted to
increase to $5.7 billion. This investment will ensure that Fortis continues to
meet the energy needs of our customers," he adds.
"We are 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 six months ended June 30, 2011
Dated August 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
six months ended June 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 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 material adverse credit rating actions are expected 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 event; the expectation that the Corporation will receive compensation from
the Government of Belize ("GOB") for the value of the Corporation's previous
investment in Belize Electricity; 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 in 2011; no severe and prolonged
downturn in economic conditions; sufficient liquidity and capital resources; the
continuation of regulator-approved mechanisms to flow through the commodity cost
of natural gas and energy supply costs in customer rates; the ability to hedge
exposures to fluctuations in interest rates, foreign exchange rates and natural
gas commodity prices; no significant variability in interest rates; no
significant counterparty defaults; the continued competitiveness of natural gas
pricing when compared with electricity and other alternative sources of energy;
the continued availability of natural gas supply; the continued ability to fund
defined benefit pension plans; the absence of significant changes in government
energy plans and environmental laws that may materially affect the operations
and cash flows of the Corporation and its subsidiaries; maintenance of adequate
insurance coverage; the ability to obtain and maintain licences and permits;
retention of existing service areas; maintenance of information technology
infrastructure; favourable relations with First Nations; favourable labour
relations; and sufficient human resources to deliver service and execute the
capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Factors which
could cause results or events to differ from current expectations include, but
are not limited to: regulatory risk; operating and maintenance risks; risk
associated with the amount of compensation to be paid to Fortis for its previous
investment in Belize Electricity; 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 six months ended June 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
approximately 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 primarily in Atlantic Canada. Year-to-date June 30, 2011, the
Corporation's electricity distribution systems met a combined peak demand of
approximately 5,028 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 six months ended
June 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 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 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") convened special sittings of
legislature to enact 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 the financial results of Belize
Electricity, effective June 20, 2011. As at June 30, 2011, the book value of the
Corporation's previous investment in Belize Electricity was $112 million which
has been classified in other long-term assets on the consolidated balance sheet
of Fortis.
In June 2008 the Public Utilities Commission of Belize ("PUC") issued a rate
order that had a significant negative impact on the financial condition and
operations of Belize Electricity. The order effectively disallowed the recovery
of $18 million of previously incurred fuel and purchased power costs in customer
rates, $13 million of which was the Corporation's share, and set customer rates
at a level that does not allow Belize Electricity to finance its operations and
earn a fair and reasonable return. Since 2008, Belize Electricity has been in
default of covenants under its long-term lending agreements, has had no access
to credit and has not paid any dividends on common shares. Belize Electricity
appealed the PUC rate order to the Supreme Court of Belize. On March 15, 2011,
the Court rendered its judgment dismissing Belize Electricity's application and
finding that, among other things, the generally accepted concept of good utility
practice is not applicable in Belize. Belize Electricity has appealed this
judgment to the Court of Appeal of Belize; however, as a result of the GOB's
actions, it is unlikely that the appeal will be prosecuted by
government-controlled Belize Electricity.
Fortis has initiated proceedings for compensation from the GOB for the value of
the Corporation's previous investment in Belize Electricity.
The GOB has indicated publicly that it does not intend to expropriate Belize
Electric Company Limited ("BECOL"), the Corporation's indirect wholly owned
non-regulated subsidiary in Belize. BECOL generates hydroelectricity from three
plants located on the Macal River with a combined generating capacity of 51 MW.
The entire output of the plants is sold to Belize Electricity under 50-year
contracts expiring in 2055 and 2060. Belize Electricity is currently purchasing
energy from BECOL at approximately US$11 cents per kilowatt hour, which is one
of the lowest-cost energy supply sources in the country of Belize. Fortis
continues to control and consolidate the financial results of BECOL. As at June
30, 2011, the book value of the Corporation's investment in BECOL was $150
million.
As at July 31, 2011, Belize Electricity owed BECOL US$6.5 million for overdue
energy purchases. The last payment received by BECOL for overdue energy
purchases totaled US$0.5 million and was received on July 11, 2011. In
accordance with long-standing agreements, the GOB guarantees the payment of
Belize Electricity's obligations to BECOL.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the second quarter and
year-to-date periods ended June 30, 2011 and June 30, 2010 are provided in the
following table.
--------------------------------------------------------------------------
Consolidated Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except
for share data) 2011 2010 Variance 2011 2010 Variance
--------------------------------------------------------------------------
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Revenue 850 835 15 2,014 1,908 106
Energy Supply Costs 358 367 (9) 961 919 42
Operating Expenses 213 202 11 425 404 21
Amortization 103 97 6 206 191 15
Finance Charges 92 88 4 183 178 5
Corporate Taxes 15 15 - 45 43 2
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Net Earnings 69 66 3 194 173 21
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Net Earnings
Attributable to:
Non-Controlling
Interests 3 3 - 4 4 -
Preference Equity
Shareholders 8 8 - 15 14 1
Common Equity
Shareholders 58 55 3 175 155 20
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69 66 3 194 173 21
----------------------====================================================
Basic Earnings per
Common Share ($) 0.33 0.32 0.01 1.00 0.90 0.10
Diluted Earnings per
Common Share ($) 0.33 0.32 0.01 0.99 0.88 0.11
Weighted Average
Number of Common
Shares Outstanding
(millions) 177.1 172.4 4.7 175.8 172.0 3.8
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Cash Flow from
Operating Activities 228 204 24 527 405 122
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Factors Contributing to Quarterly Revenue Variance
Favourable
-- Gas and energy sales growth, mainly due to weather-related increases in
consumption, and growth in the number of customers at FortisAlberta
-- 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.
-- An increase in gas delivery rates and the base component of electricity
rates at several of the utilities, consistent with rate case decisions,
reflecting ongoing investment in utility infrastructure and higher
regulator-approved expenses recoverable from customers
-- The flow through in customer electricity rates of overall higher energy
supply costs driven by Caribbean Utilities and Maritime Electric
-- The recognition of $2.5 million of accrued revenue at FortisAlberta
during the second quarter of 2011 related primarily to the cumulative
2010 and year-to-date 2011 return and 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
-- The discontinuance of the consolidation method of accounting for the
financial results of Belize Electricity, effective June 20, 2011
-- Increased performance-based rate-setting ("PBR") incentive adjustments
owing to customers by FortisBC Electric
-- Approximately $6 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
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- Gas and energy sales growth for the same reasons as discussed above for
the quarter
-- The timing of recording of the cumulative impacts of FortisAlberta's and
FEWI's 2010 revenue requirements decisions. The impacts of the rate
decisions were recorded during the third quarter of 2010 when the
decisions were received.
-- The increase in gas delivery rates and the base component of electricity
rates, as discussed above for the quarter
-- The flow through in customer electricity rates of overall higher energy
supply costs
-- The $2.5 million of accrued revenue associated with the cumulative
return and amortization on the additional capital expenditures included
in rate base associated with the Automated Metering Project, as
discussed above for the quarter
-- An approximate $1 million gain on sale of property during the first
quarter of 2011
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Increased PBR incentive adjustments, as discussed above for the quarter
-- Decreased amortization of regulatory liabilities and deferrals at
Newfoundland Power, as approved by the regulator
-- Approximately $10 million associated with unfavourable foreign currency
translation
Factors Contributing to Quarterly Energy Supply Costs Variance
Favourable
-- Lower commodity cost of natural gas
-- Lower average market-priced purchased power costs at FortisBC Electric
and FortisOntario
-- Approximately $3 million associated with favourable foreign currency
translation
-- The discontinuance of the consolidation method of accounting for the
financial results of Belize Electricity, effective June 20, 2011
Unfavourable
-- Gas and energy sales growth
-- Higher energy supply costs associated with increased fuel costs at
Caribbean Utilities and an increase in the recovery of energy supply
costs at Maritime Electric through the operation of the Energy Cost
Adjustment Mechanism
Factors Contributing to Year-to-Date Energy Supply Costs Variance
Unfavourable
-- The same factors as discussed above for the quarter
Favourable
-- Lower commodity cost of natural gas
-- Lower average market-priced purchased power costs at FortisBC Electric
and FortisOntario
-- Approximately $6 million associated with favourable foreign currency
translation
Factors Contributing to Quarterly and Year-to-Date Operating Expenses Variances
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, and the timing of labour costs
-- Wage and general inflationary increases
-- The timing of and regulator-approved increase in certain operating
expenses at the FortisBC Energy companies
Favourable
-- Higher corporate operating expenses incurred in the first half of 2010
related to business development costs
Factors Contributing to Quarterly and Year-to-Date Amortization Costs Variances
Unfavourable
-- Higher amortization rates 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.
-- Continued investment in utility infrastructure and income producing
properties
Favourable
-- Reduced amortization costs 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
-- Increased amortization costs during the first half of 2010 at
Newfoundland Power, due to approximate $1 million and $2 million
adjustments for the second quarter and year-to-date periods of 2010,
respectively, as approved by the regulator, related to an amortization
study
Factors Contributing to Quarterly and Year-to-Date Finance Charges Variances
Unfavourable
-- Higher debt levels in support of the utilities' capital expenditure
programs
Favourable
-- The refinancing of maturing corporate debt at a lower rate in April 2010
-- Higher capitalized allowance for funds used during construction year to
date
Factors Contributing to Quarterly and Year-to-Date Corporate Taxes Variances
Favourable
-- Lower effective corporate income tax rate, driven by higher deductions
for income tax purposes compared to accounting purposes and lower
statutory income tax rates
Unfavourable
-- Higher earnings before corporate taxes
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- An approximate $6 million and $10.5 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
-- The $2.5 million of accrued revenue associated with the cumulative
return and amortization on the additional capital expenditures included
in rate base associated with the Automated Metering Project, as
discussed above
-- The favourable impact year to date of the timing of recording of the
cumulative impacts of FortisAlberta's and FEWI's 2010 revenue
requirements decisions. The impacts of the rate decisions were recorded
during the third quarter of 2010 when the decisions were received.
-- Lower average market-priced purchased power costs at FortisBC Electric
-- The favourable impact year to date of higher energy sales driven by
FortisBC Electric and FortisAlberta
-- Higher corporate operating expenses incurred in the first half of 2010
related to business development costs
-- Higher capitalized allowance for funds used during construction year to
date related to the construction of the liquefied natural gas ("LNG")
storage facility on Vancouver Island
-- A higher allowed ROE at Algoma Power
Unfavourable
-- The timing of and regulator-approved increase in certain operating
expenses at the FortisBC Energy companies
-- Decreased earnings from non-regulated hydroelectric generation
operations for the quarter reflecting decreased production at BECOL due
to lower rainfall
-- Lower earnings from Fortis Properties reflecting lower occupancies at
hotel operations in western Canada, combined with increased operating
expenses
SEGMENTED RESULTS OF OPERATIONS
---------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy Companies 15 17 (2) 91 90 1
---------------------------------------------------------------------------
Regulated Electric Utilities -
Canadian
FortisAlberta 19 17 2 40 32 8
FortisBC Electric 9 8 1 28 22 6
Newfoundland Power 11 11 - 18 18 -
Other Canadian Electric
Utilities 6 4 2 12 9 3
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45 40 5 98 81 17
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Regulated Electric Utilities -
Caribbean 7 7 - 10 11 (1)
Non-Regulated - Fortis Generation 2 3 (1) 5 5 -
Non-Regulated - Fortis Properties 7 8 (1) 9 10 (1)
Corporate and Other (18) (20) 2 (38) (42) 4
---------------------------------------------------------------------------
Net Earnings Attributable to
Common Equity Shareholders 58 55 3 175 155 20
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For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Corporation's regulated utilities, refer to
the "Regulatory Highlights" section of this MD&A. A discussion of the financial
results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
----------------------------------------------------------------------------
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
(TJ) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Core - Residential and
Commercial 24,951 23,827 1,124 75,399 64,258 11,141
Industrial 1,229 1,193 36 3,117 2,868 249
----------------------------------------------------------------------------
Total Sales Volumes 26,180 25,020 1,160 78,516 67,126 11,390
Transportation Volumes 16,730 14,090 2,640 37,214 30,500 6,714
Throughput under Fixed
Revenue
Contracts 489 2,374 (1,885) 965 6,766 (5,801)
----------------------------------------------------------------------------
Total Gas Volumes 43,399 41,484 1,915 116,695 104,392 12,303
----------------------------------------------------------------------------
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(1) The FortisBC Energy companies are comprised of FEI, FEVI and FEWI.
Factors Contributing to Quarterly and Year-to-Date Gas Volumes Variances
Favourable
-- Higher average consumption by residential and commercial customers as a
result of cooler weather
-- Higher transportation volumes reflecting improving economic conditions
favourably affecting the forestry sector
Unfavourable
-- Lower volumes under fixed revenue contracts, mainly due to higher
precipitation, which made it more cost efficient for a large customer to
not utilize its natural gas-powered generating facility during the first
half of 2011
Net customer additions were 1,002 during the first half of 2011 compared to
1,829 during the first half of 2010. Gross customer additions decreased due to
lower building activity during 2011.
Seasonality has a material impact on the earnings of the FortisBC Energy
companies as a major portion of the gas distributed is used for space heating.
Most of the annual earnings of the FortisBC Energy companies are realized in the
first and fourth quarters.
The FortisBC Energy companies earn approximately the same margin regardless of
whether a customer contracts for the purchase and delivery of natural gas or for
the transportation only of natural gas. As a result of the operation of
regulator-approved deferral mechanisms, changes in consumption levels and energy
supply costs from those forecast to set residential and commercial customer gas
rates do not materially affect earnings.
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 320 336 (16) 895 862 33
Earnings 15 17 (2) 91 90 1
--------------------------------------------------------------------------
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Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
Favourable
-- Higher average gas consumption by residential and commercial customers
-- Higher transportation volumes in the forestry sector
-- 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 factors as discussed above for the quarter
-- The timing of recording of the cumulative impact of FEWI's 2010 revenue
requirements decision. The impact of the rate decision was recorded
during the third quarter of 2010.
Unfavourable
-- The same factor as discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- The timing of and regulator-approved increase in operating expenses,
driven by labour and benefits costs and consulting expenses
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
-- Reduced amortization costs, mainly due to the retirement late in 2010 of
certain general plant assets
-- Higher transportation volumes in the forestry sector
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
-- The timing of recording of the cumulative impact of FEWI's revenue
requirements decision, as discussed above
-- Higher capitalized allowance for funds used during construction related
to the construction of the LNG storage facility
Unfavourable
-- The same factor as discussed above for the quarter
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (gigawatt
hours ("GWh")) 3,822 3,784 38 8,224 7,833 391
Revenue ($ millions) 104 92 12 207 180 27
Earnings ($ millions) 19 17 2 40 32 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Energy Deliveries Variance
Favourable
-- Lower average consumption during the second quarter of 2010 by
residential, commercial and oilfield customers
-- Customer growth, with the total number of customers increasing by
approximately 9,400 quarter over quarter
Unfavourable
-- Decreased energy deliveries to farm and irrigation customers, due to
differences in rainfall period over period
-- Lower energy deliveries to other industrial customers
Factors Contributing to Year-to-Date Energy Deliveries Variance
Favourable
-- Increased average consumption by residential and commercial customers
due to temperature differences period over period
-- Increased activity in the oil and gas sector
-- Growth in the number of customers, as discussed above for the quarter
As a significant portion of FortisAlberta's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue. Revenue is a
function of numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The recognition of $2.5 million of accrued revenue during the second
quarter of 2011 related primarily to the cumulative 2010 and year-to-
date 2011 return and 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. For further
information, refer to the "Material Regulatory Decisions and
Applications - FortisAlberta" section of this MD&A.
-- A 4.7% increase in base customer electricity distribution rates over
final-approved 2010 rates, effective January 1, 2011, associated with
the 2010-2011 regulatory rate decision. The increase in base rates was
primarily due to ongoing investment in utility infrastructure.
-- Revenue for the first half of 2010 reflected a 7.5% interim customer
rate increase, whereas revenue for the first half of 2011 reflected the
full impact of approved rate increases as provided in the 2010-2011
regulatory rate decision. The cumulative impact from January 1, 2010 of
the rate decision was recorded during the third quarter of 2010 when the
decision was received. The final-approved customer rate increase for
2010 was 20.1% related to the distribution component of customer rates.
-- Growth in the number of customers
Unfavourable
-- Lower net transmission revenue. Effective January 1, 2010, as a result
of the 2010-2011 regulatory rate decision that was received, and the
effects of which were recorded during the third quarter of 2010, all
transmission costs and revenue are deferred to be recovered from, or
refunded to, customers in future rates.
-- Lower miscellaneous revenue for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- The $2.5 million of accrued revenue associated with the cumulative
return and amortization on the additional capital expenditures included
in rate base associated with the Automated Metering Project, as
discussed above
-- Rate base growth, due to continued investment in utility infrastructure
Unfavourable
-- Lower net transmission revenue
-- Lower-than-expected customer growth and energy deliveries to farm and
irrigation customers
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors as discussed above for the quarter
-- The timing of recording of the cumulative impact of FortisAlberta's
2010-2011 regulatory rate decision. The impact of the decision was
recorded in the third quarter of 2010 when the decision was received.
-- Higher energy deliveries to residential and commercial customers
Unfavourable
-- Lower net transmission revenue
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 682 671 11 1,587 1,491 96
Revenue ($ millions) 64 59 5 148 131 17
Earnings ($ millions) 9 8 1 28 22 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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-normal temperatures experienced during that period
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 and
the higher cost of capital
-- 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 1.6% and 6.4% increase in electricity sales for the quarter and year
to date, respectively
-- Higher revenue contribution from non-regulated operating, maintenance
and management services
Unfavourable
-- Increased PBR incentive adjustments owing to customers
-- Lower pole attachment revenue, partially offset by higher wheeling
revenue
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- Rate base growth, due to continued investment in utility infrastructure
-- Lower-than-expected average consumption in the first quarter of 2010 for
the reason discussed above
-- Lower-than-expected average market-priced purchased power costs
Unfavourable
-- Higher-than-expected PBR-incentive adjustments owing to customers,
driven by the lower-than-expected average market-priced purchased power
costs
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 1,269 1,220 49 3,103 3,015 88
Revenue ($ millions) 133 126 7 316 304 12
Earnings ($ millions) 11 11 - 18 18 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption reflecting higher concentration of electric
heating in new homes combined with strong economic growth
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 4.0% and 2.9% 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
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- The decrease in the allowed ROE, as reflected in customer rates
-- Wage and inflationary increases
-- Timing of labour costs as a result of higher capital work performed in
the first half of 2010, due to an early start of the capital program and
restoration work related to an ice storm in March 2010, as well as a
significant portion of certain employee initiatives were completed
during the first half of 2011
Favourable
-- Electricity sales growth
-- Lower effective corporate income taxes in 2011, primarily due to a lower
statutory income tax rate
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 562 535 27 1,216 1,167 49
Revenue ($ millions) 78 75 3 169 157 12
Earnings ($ millions) 6 4 2 12 9 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
-- Higher average consumption, reflecting colder temperatures in Ontario
and Prince Edward Island ("PEI")
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 5.0% and 4.2% increase in electricity sales for the quarter and year
to date, respectively
-- 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
Unfavourable
-- The flow through in customer electricity rates of lower energy supply
costs at FortisOntario
-- The flow through to customers of lower power purchase costs charged by
New Brunswick Power ("NB Power") as a result of a new five-year power
purchase agreement between Maritime Electric and NB Power
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- A higher allowed ROE at Algoma Power, as reflected in customer rates
-- Electricity sales growth
-- A deferred start to the vegetation management program in Ontario during
2011
-- Lower effective corporate income taxes at FortisOntario in 2011,
primarily due to higher deductions taken for income tax purposes
compared to accounting purposes during the second quarter of 2011
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate
(2) 0.97 1.03 (0.06) 0.98 1.03 (0.05)
Electricity Sales (GWh) 290 307 (17) 547 562 (15)
Revenue ($ millions) 87 83 4 162 159 3
Earnings ($ millions) 7 7 - 10 11 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 the financial results of
Belize Electricity, effective June 20, 2011. For further information,
refer to the "Corporate Overview" section 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 the financial results of Belize Electricity, effective
June 20, 2011. For further information, refer to the "Corporate
Overview" section of this MD&A.
-- The loss at Belize Electricity of a large industrial customer that began
generating its own electricity during the fourth quarter of 2010
-- Tempered energy consumption due to persistent challenging economic
conditions in the region combined with a declining population on Grand
Cayman
-- Cooler weather conditions experienced on Grand Cayman during the second
quarter of 2011, which decreased air conditioning load, partially offset
by warmer and drier weather conditions experienced during the first
quarter of 2011
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
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the cost of fuel
-- A commercial customer billing adjustment at Caribbean Utilities
Unfavourable
-- The discontinuance of the consolidation method of accounting for the
financial results of Belize Electricity, effective June 20, 2011
-- Approximately $5 million and $10 million unfavourable foreign exchange
for the quarter and year to date, respectively, associated with the
translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar
-- Lower electricity sales on Grand Cayman
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Lower electricity sales on Grand Cayman
-- The discontinuance of the consolidation method of accounting for the
financial results of Belize Electricity, effective June 20, 2011
-- Higher finance charges at Belize Electricity due to interest expense on
regulatory liabilities
Favourable
-- Ongoing efforts of reducing costs and improving efficiencies to temper
the impact of persistent challenging economic conditions in the region
-- Lower corporate taxes at Belize Electricity. Corporate taxes in the
second quarter of 2010 reflected an increase in the business tax rate to
6.5% from 1.75%, effective April 1, 2010. During the third quarter of
2010, the previously expensed increase in business taxes was reversed
and deferred for future collection from customers.
-- A commercial customer billing adjustment at Caribbean Utilities
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 90 87 3 166 156 10
Revenue ($ millions) 7 8 (1) 14 13 1
Earnings ($ millions) 2 3 (1) 5 5 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State, with a combined generating capacity of 139 megawatts,
mainly hydroelectric. Results reflect contribution from the Vaca
hydroelectric generating facility in Belize from late March 2010 when
the facility was commissioned.
Factors Contributing to Quarterly and Year-to-Date Energy Sales Variances
Favourable
-- Increased production in Upper New York State and Ontario, due to higher
rainfall
Unfavourable
-- Decreased production in Belize due to lower 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. The average rate per MWh for the second quarter
of 2011 was $72.09 compared to $50.72 for the same quarter in 2010. The
average rate per MWh for the first half of 2011 was $72.34 compared to
$38.40 for the first half of 2010. Effective May 1, 2010, energy
produced in Ontario is being sold under a fixed-price contract with
price indexing. Previously, energy was sold at market rates.
-- Increased production in Upper New York State
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Decreased production in Belize
-- Higher finance charges as a result of lower interest revenue associated
with lower inter-company lending to regulated operations in Ontario
Favourable
-- Increased production and higher average energy sales rates in Ontario
-- Increased production in Upper New York State
NON-REGULATED - FORTIS PROPERTIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality Revenue 43 43 - 76 76 -
Real Estate Revenue 17 17 - 34 33 1
----------------------------------------------------------------------------
Total Revenue 60 60 - 110 109 1
----------------------------------------------------------------------------
Earnings 7 8 (1) 9 10 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 21 hotels, comprised of more than
4,100 rooms, in eight Canadian provinces and approximately 2.7
million square feet of commercial office and retail space primarily
in Atlantic Canada.
Factors Contributing to Quarterly Revenue Variance
Favourable
-- Rent increases at the Real Estate Division
Unfavourable
-- A 0.2% decrease in revenue per available room ("RevPar") at the
Hospitality Division to $83.57 for the second quarter of 2011 from
$83.77 for the same quarter in 2010. RevPar decreased due to an overall
2.2% decrease in hotel occupancy, most significantly in western Canada,
partially offset by an overall 2.0% increase in the average daily room
rate. The average daily room rate increased in all regions.
-- A decrease in the occupancy rate at the Real Estate Division to 93.4% as
at June 30, 2011 from 94.8% as at June 30, 2010, mainly associated with
increased vacancy at operations in Newfoundland and New Brunswick
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- 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
Unfavourable
-- The decrease in the occupancy rate at the Real Estate Division, as
discussed above for the quarter
-- A 0.1% decrease in RevPar at the Hospitality Division to $73.41 for the
first half of 2011 from $73.45 for the first half of 2010. RevPar
decreased due to an overall 1.8% decrease in hotel occupancy, partially
offset by an overall 1.7% increase in the average daily room rate. Hotel
occupancy at operations in western Canada decreased, while occupancy at
operations in central Canada increased. The average daily room rate
increased in all regions.
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Lower performance of hotel operations, driven by the continued
unfavourable impact of decreased occupancies at hotel operations in
western Canada
-- Higher operating expenses due to inflationary pressures
-- Higher amortization costs year to date due to capital investment in both
the Hospitality and Real Estate Divisions
Favourable
-- The $0.5 million gain on the sale of the Viking Mall
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 8 9 (1) 15 15 -
Operating Expenses 3 6 (3) 4 10 (6)
Amortization 1 1 - 3 4 (1)
Finance Charges (2) 18 18 - 37 38 (1)
Corporate Tax Recovery (4) (4) - (6) (9) 3
--------------------------------------------------
(10) (12) 2 (23) (28) 5
Preference Share Dividends 8 8 - 15 14 1
----------------------------------------------------------------------------
Net Corporate and Other
Expenses (18) (20) 2 (38) (42) 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
-- Reduced operating expenses. Operating expenses were higher during the
first half of 2010 due to business development costs incurred during
that period.
-- Lower finance charges year to date, driven by the redemption of $125
million 8.0% Capital Securities in April 2010 and the favourable foreign
exchange impact associated with the translation of US dollar-denominated
interest expense, partially offset by the impact of higher average
credit facility borrowings combined with higher interest rates charged
on those credit facility borrowings
Unfavourable
-- Lower corporate tax recovery year to date, mainly due to a lower net
loss for income tax purposes
-- Higher preference share dividends year to date, due to the issuance of
First Preference Shares, Series H in January 2010
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the first half of 2011 are summarized as follows:
NATURE OF REGULATION
----------------------------------------------------------------------------
Supportive
Features
Future or
Allowed Historical Test
Common Year
Regulated Regulatory Equity Used to Set
Utility Authority (%) Allowed Returns (%) Customer Rates
---------------------------
2009 2010 2011
----------------------------------------------------------------------------
ROE COS/ROE
---------------------------
FEI British 40(1) 8.47(2) 9.50 9.50
Columbia /9.50(3) FEI: Prior to
Utilities January 1,
Commission 2010, 50/50
("BCUC") sharing of
earnings above
or below
the allowed ROE
under a PBR
mechanism that
expired on
December 31,
2009 with a
two-year
FEVI BCUC 40 9.17(2) 10.00 10.00 phase-out
/10.00(3)
ROEs
FEWI BCUC 40 8.97(2) 10.00 10.00 established by
/10.00(3) 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
----------------------------------------------------------------------------
Newfoundland Newfoundland 45 8.95 +/- 9.00 +/- 8.38 +/- COS/ROE
Power and Labrador 50 bps 50 bps 50 bps
Board of
Commissioners
of Public
Utilities
("PUB")
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 Energy Canadian
Ontario Board ("OEB") Niagara Power -
Canadian 40(5) 8.01 8.01 8.01 COS/ROE
Niagara Power
Algoma 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
---------------------------
Caribbean Electricity N/A 9.00 - 7.75 - 7.75 - COS/ROA
Utilities Regulatory 11.00 9.75 9.75
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 Turks Utilities N/A 17.50(8) 17.50(8) 17.50(8) COS/ROA
and Caicos make annual
filings to
the Governor
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 requested a review of its rates in 2010.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
----------------------------------------------------------------------------
Regulated
Utility Summary Description
----------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review natural gas and propane commodity and
mid-stream rates with the BCUC every three months in order
to ensure the flow-through rates charged to customers are
sufficient to cover the cost of purchasing natural gas and
propane and contracting for mid-stream resources, such as
third-party pipeline 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 balances in the Commodity Cost
Reconciliation Account and Mid-Stream Cost Reconciliation
Account ("MCRA") are recovered on a timely basis, FEI and
FEWI prepare and file quarterly calculations with the BCUC
to determine whether customer rate adjustments are needed to
reflect prevailing market prices for natural gas 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, 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.
- 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.
- FEI, FEVI and FEWI are expecting to file an application
with the BCUC during the third quarter of 2011 for the
amalgamation of the three companies. An amalgamation would
require an application to be approved by the BCUC and
consent of the Government of British Columbia.
- In January 2011 FEI filed its review of the Price Risk
Management Plan ("PRMP") objectives with the BCUC related to
its gas commodity hedging plan and also submitted a 2011-
2014 PRMP. In June 2011 FEVI filed a 2012-2013 hedging
request application. In July 2011 the BCUC denied FEI's
2011-2014 PRMP with the exception of certain elements
related to basis swaps. 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 May 2011 the FortisBC Energy companies filed their
2012-2013 Revenue Requirements Applications. FEI requested a
2.8% increase in customer delivery rates effective January
1, 2012 and a 3.0% increase, effective January 1, 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. FEI's application
assumes forecast average rate base of approximately $2,737
million for 2012 and $2,788 million for 2013. FEVI requested
that customer delivery rates remain unchanged for the two-
year period beginning January 1, 2012. FEVI's application
assumes forecast average rate base of $788 million for 2012
and $814 million for 2013.
- 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 in 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.
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FortisBC - In December 2010 the BCUC approved a Negotiated Settlement
Electric 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 and the higher cost of capital.
- In June 2011 FortisBC Electric filed its 2012-2013 Revenue
Requirements Application 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 infrastructuure,
increasing 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.
- Effective June 1, 2011, the BCUC approved a refundable
interim increase of 1.4% in FortisBC Electric customer rates
arising from an increase in purchased power costs due to an
interim increase in BC Hydro rates.
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FortisAlberta - In December 2010 the AUC issued its decision on
FortisAlberta's August 2010 Compliance Filing, which
incorporated the AUC's decision, received in July 2010, on
the Company's 2010 and 2011 Distribution Tariff Application
("DTA"). The December 2010 decision approved the Company's
distribution revenue requirements of $368 million for 2011.
Final distribution electricity rates and rate riders were
also approved, effective January 1, 2011.
- During the first quarter of 2011, the AUC initiated its
proceeding to finalize the allowed ROE for 2011, review
capital structure and consider whether a return to a
formula-based approach for annually setting the allowed ROE,
beginning in 2012, is warranted. In the absence of a
formula-based approach, the AUC is expected to consider how
the allowed ROE will be set for 2012. A hearing on the
proceeding 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 rate base growth
associated with investment in utility infrastructure, which
results in increased amortization costs and interest
expense. The Company has proposed a schedule for the DTA
proceeding that would include a hearing in late October 2011
with a final decision expected in the first quarter of 2012.
- 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 forecast total project cost of $126 million can be
included in rate base and collected in customer rates. The
impact of the decision is the recognition of $2.5 million in
accrued revenue and an associated regulatory asset as at
June 30, 2011. The Utilities Consumer Advocate has filed a
Leave to Appeal related to this decision.
- In October 2010 the Central Alberta Rural Electrification
Association ("CAREA") filed an application with the AUC
seeking a declaration that, effective January 1, 2012, CAREA
be entitled to service any new customer wishing to obtain
electricity for use on property within CAREA's service area
and that FortisAlberta be restricted to serving only those
customers that are not being provided service by CAREA.
FortisAlberta has intervened in the proceeding.
- The AUC has initiated a process to reform utility rate
regulation in Alberta. The AUC has expressed its intention
to apply a PBR formula to 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.
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Newfoundland - In November 2010 the PUB approved Newfoundland Power's
Power application to defer the recovery of expected increased
costs of $2.4 million, due to expiring regulatory
amortizations in 2011.
- In December 2010 the PUB approved Newfoundland Power's
application to: (i) adopt the accrual method of accounting
for OPEB costs, effective January 1, 2011; (ii) recover the
transitional regulatory asset balance of approximately $53
million, associated with adoption of accrual accounting,
over a 15-year period; and (iii) adopt an OPEB cost-variance
deferral account to capture differences between OPEB expense
calculated in accordance with Canadian GAAP and OPEB expense
approved by the PUB for rate-setting purposes.
- In December 2010 Newfoundland Power received approval from
the PUB for an overall average 0.8% increase in customer
electricity rates, effective January 1, 2011, mainly
resulting from the PUB's approval for the Company to change
its accounting for OPEB costs, as described above, partially
offset by the impact of the decrease in the allowed ROE for
2011.
- On January 1, 2011, new support structure arrangements
with Bell Aliant Inc. ("Bell Aliant" or the "Purchaser")
went into effect. Bell Aliant will buy back 40% of all
joint-use poles and related infrastructure owned by
Newfoundland Power for approximately $46 million,
representing approximately 5% of the Company's rate base.
The support structure arrangements are subject to certain
conditions, including PUB approval of the sale of 40% of the
Company's joint-use poles, which were to be met by June 30,
2011, or either party could terminate the new arrangements.
Newfoundland Power filed an application with the PUB in
February 2011 seeking approval of the transaction. On July
22, 2011, the PUB issued an order that denied Newfoundland
Power's application requesting approval of the proposed
sale. The PUB indicated that there was lack of evidence to
support the customer benefits related to this transaction.
The Company is presently reviewing the order and its
options, including whether to appeal the PUB decision or
file further evidence to support the PUB's reconsideration
of the proposed sale. The purchase price continues to be
held in escrow and Newfoundland Power is negotiating with
the Purchaser to facilitate the successful completion of the
transaction. In the event of termination, the rights and
recourses under the original Joint-Use Facilities
Partnership Agreement will remain in effect for both
parties. Due to the timing of the PUB decision, and range of
options available, it is not practicable at this time to
determine the financial impact, if any, the decision has on
Newfoundland Power. 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. Newfoundland Power anticipates the proceeds from the
sale of the poles will be used to pay down credit facility
borrowings and maintain the utility's capital structure at
45% common equity.
- In April 2011 the PUB approved Newfoundland Power's
application requesting an Optional Seasonal Rate for
domestic customers effective July 1, 2011. This Optional
Seasonal Rate charges a higher price for electricity
consumed during the months of December through April and a
lower rate during the months of May through November. The
PUB also approved capital expenditures for 2011 required to
facilitate implementation of the Optional Seasonal Rate and
the use of an Optional Rates Revenue and Cost Recovery
Account that provides for the deferral of annual cost and
revenue effects associated with implementing the Optional
Seasonal Rate.
- Effective July 1, 2011, the PUB approved an overall
average increase in customer electricity rates of
approximately 8%. 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.
- As part of its 2011 Budget, the Government of Newfoundland
and Labrador introduced the Energy Rebate which will result
in the 8% provincial portion of the Harmonized Goods and
Services Tax on home energy purchases, including
electricity, being refunded to residential customers. This
rebate is expected to be in place by October 1, 2011.
Details regarding the Energy Rebate's application and
implementation date are expected to be finalized over the
summer months for implementation in early fall 2011.
- In July 2011 Newfoundland Power filed an application with
the PUB requesting approval for its 2012 Capital Expenditure
Plan totalling approximately $77 million.
- The Company is currently assessing the requirement for it
to file an application with the PUB to recover expected
increased costs in 2012.
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Maritime - In November 2010 Maritime Electric signed an Accord with
Electric the Government of PEI. The Accord covers the period from
March 1, 2011 through February 29, 2016. Under the terms of
the Accord, the Government of PEI is assuming responsibility
for the cost of replacement energy and the monthly operating
and maintenance costs related to the NB Power Point Lepreau
Nuclear Generating Station ("Point Lepreau"), effective
March 1, 2011 until Point Lepreau is fully refurbished,
which is expected by fall 2012. The Government of PEI is
financing these costs, which will be recovered from
customers beginning when Point Lepreau returns to service.
In the event that Point Lepreau does not return to service
by fall 2012, the Government of PEI reserves the right to
cease the monthly payments. As permitted by IRAC,
replacement energy costs incurred during the refurbishment
of Point Lepreau up to the end of February 2011 were
deferred by Maritime Electric and totalled approximately $47
million. The deferred costs are included in rate base.
- 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 high 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 subsequently collected from
customers over a period to be established by the Government
of PEI. As a result of the Accord, including the favourable
impact on purchased power costs of the new five-year power
purchase agreement between Maritime Electric and NB Power,
customer electricity rates decreased by approximately 14%
effective March 1, 2011, at which time a two-year customer
rate freeze commenced.
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FortisOntario - In non-rebasing years, customer electricity distribution
rates are set using inflationary factors less an efficiency
target under the Third-Generation Incentive Rate Mechanism
("IRM") as prescribed by the OEB. In March 2011 the OEB
published the applicable inflationary and efficiency
targets, which resulted in minimal changes in base customer
electricity distribution rates at FortisOntario's operations
Fort Erie, Gananoque and Port Colborne.
- In November 2010 the OEB approved an NSA pertaining to
Algoma Power's electricity distribution rate application for
customer rates, effective December 1, 2010 through December
31, 2011, using a 2011 forward test year. The rates reflect
an approved allowed ROE of 9.85% on a deemed equity
component of capital structure of 40%. The overall impact of
the OEB rate decision on an overall average customer's
electricity bill was an increase of 3.8%, including rate
riders and other charges.
- The present form of Third-Generation IRM will not
accommodate Algoma Power's customer rate structure and the
RRRP Program; therefore, Algoma Power is consulting 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. Pending these consultations, Algoma
Power will file for incentive rate-making for customer
electricity distribution rates, effective January 1, 2012.
- FortisOntario expects to file a COS Application in 2012
for harmonized electricity distribution rates in Fort Erie,
Port Colborne and Gananoque, effective January 1, 2013,
using a 2013 forward test year. The timing of the filing of
the COS Application corresponds with the ending of the
period that the current Third-Generation IRM applies to
FortisOntario.
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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 upon the basis of
the Company's application to the ERA for a delay in any new
generation installation until there is more certainty in
growth forecasts. The remaining US$85 million of the CIP
relates to new generation installation, which would be
subject to a competitive solicitation process with the next
generating unit currently scheduled for installation in
2014.
- In July 2011 the ERA approved Caribbean Utilities request
to use US GAAP for regulatory reporting purposes, beginning
January 1, 2012.
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Fortis Turks - In March 2011 Fortis Turks and Caicos submitted its 2010
and 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 for 2010
of US$142 million and cumulative shortfall in achieving
allowable profits as at December 31, 2010 of US$49 million.
- In June 2011 Fortis Turks and Caicos was advised by the
interim Government of the Turks and Caicos Islands of its
intention to conduct an independent review of the regulatory
framework for the electricity sector in the Turks and Caicos
Islands. The review is expected to be completed during the
third quarter of 2011. Fortis Turks and Caicos expects to
file a new Rate Variance Application in 2011.
- Effective September 2011 the interim Government of the
Turks and Caicos Islands plans to implement a carbon tax
which will be applicable to Fortis Turks and Caicos but
which may not be permitted to be passed onto Fortis Turks
and Caicos' customers. If the carbon tax is implemented as
scheduled, the potential impact on Fortis Turks and Caicos
is a decrease in earnings of approximately $1 million for
2011. Management is working with the interim Government for
a mutually beneficial resolution of the above issue.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between June 30, 2011 and December 31, 2010.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
June 30, 2011 and December 31, 2010
----------------------------------------------------------------------------
Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
----------------------------------------------------------------------------
Cash 189 The increase was driven by cash on hand
related to a portion of the proceeds from
the June 2011 $300 million common share
issue.
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Accounts (66) The decrease was primarily due to the impact
receivable of a seasonal decrease in sales and the
lower commodity cost of natural gas
reflected in customer rates at the FortisBC
Energy companies and the discontinuance of
the consolidation method of accounting for
the financial results of Belize Electricity
in June 2011. The decrease was partially
offset by the operation of the equal payment
plans for customers mainly at the FortisBC
Energy companies and Newfoundland Power.
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Inventories (60) The decrease was driven by the normal
seasonal reduction of gas in storage at the
FortisBC Energy companies, due to higher
consumption during the winter months.
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Other assets 109 The increase was due to the discontinuance
of the consolidation method of accounting
for the financial results of 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
unrealized foreign currency translation
losses of $28 million, to other assets.
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Utility capital 84 The increase primarily related to $487
assets million invested in electricity and gas
systems, partially offset by the impact of
the discontinuance of the consolidation
method of accounting for Belize Electricity,
and amortization costs and customer
contributions for the six months ended June
30, 2011.
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Short-term (201) The decrease was driven by lower borrowings
borrowings at the FortisBC Energy companies due to
seasonality of operations and repayment of
borrowings by way of equity injection from
Fortis with a portion of the proceeds from
the June 2011 equity issue.
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Accounts payable (106) The decrease was mainly due to: (i) a change
and accrued in the fair market value of the natural gas
charges derivatives at the FortisBC Energy
companies; (ii) lower amounts owing for
purchased natural gas at the FortisBC Energy
companies and purchased power at FortisBC
Electric and Newfoundland Power, associated
with seasonality of operations; and (iii)
the discontinuance of the consolidation
method of accounting for Belize Electricity.
The decrease was partially offset by 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"), and at
Caribbean Utilities due to an increase in
fuel costs.
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Regulatory 66 The increase was mainly due to: (i)
liabilities - increased deferrals at the FortisBC Energy
current and long- companies; (ii) an increase in the provision
term for asset removal and site restoration costs
at FortisAlberta; and (iii) increases in the
weather normalization and other deferral
accounts at Newfoundland Power. The
increased deferrals at the FortisBC Energy
companies were associated with the Rate
Stabilization Deferral Account ("RSDA"),
reflecting the accumulation of over-
recovered costs of providing service to
customers during the first half of 2011, the
MCRA, as amounts collected in customer rates
were in excess of actual mid-stream gas-
delivery costs, 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.
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Shareholders' 433 The increase was driven by the issuance of
equity (before $300 million in common shares in June 2011.
non-controlling The net proceeds are being used to repay
interests) borrowings under credit facilities, fund
equity injections into the utilities in
western Canada and the non-regulated Waneta
Partnership in support of infrastructure
investment, and for general corporate
purposes.
The remainder of the increase in
shareholders' equity was primarily due to:
(i) the reclassification of $28 million of
unrealized foreign currency translation
losses related to the Corporation's previous
investment in Belize Electricity from
accumulated other comprehensive loss to
other long-term assets; (ii) net earnings
attributable to common equity shareholders
for the six months ended June 30, 2011, less
common share dividends; and (iii) the
issuance of common shares under the
Corporation's dividend reinvestment and
stock option plans.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the three and six months ended June 30, 2011, as compared to the same
periods in 2010, followed by a discussion of the nature of the variances in cash
flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30 Quarter Ended Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
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Cash, Beginning of Period 86 92 (6) 109 85 24
Cash Provided by (Used
in):
Operating Activities 228 204 24 527 405 122
Investing Activities (268) (229) (39) (487) (405) (82)
Financing Activities 252 3 249 149 (14) 163
Effect of Exchange Rate
Changes on
Cash and Cash
Equivalents - 1 (1) - - -
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Cash, End of Period 298 71 227 298 71 227
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $24 million higher quarter over quarter and $122
million higher year to date compared to the same period last year. The increases
were primarily due to: (i) higher earnings; (ii) the collection from customers
of regulator-approved increased amortization costs, mainly at FortisAlberta; and
(iii) favourable changes in working capital and regulatory deferral accounts.
The favourable working capital changes were driven by greater impacts of
seasonality at the FortisBC Energy companies and higher Alberta Electric System
Operator ("AESO") net transmission-related receipts and payments at
FortisAlberta. The favourable changes in regulatory deferral accounts related
mainly to the increase in the RSDA at the FortisBC Energy companies, due to the
accumulation of over-recovered costs of providing service to customers during
2011.
Investing Activities: Cash used in investing activities was $39 million higher
quarter over quarter and $82 million higher year to date compared to the same
period last year. The increases were driven by capital spending related to the
non-regulated Waneta Expansion Project and an increase in capital spending at
FortisAlberta year to date, partially offset by lower capital spending at
FortisBC Electric and an increase in contributions received in aid of
construction.
Financing Activities: Cash provided by financing activities was $249 million
higher quarter over quarter and $163 million higher year to date compared to the
same period last year. The increases were mainly due to higher proceeds from the
issuance of common shares, lower repayments of long-term debt, higher advances
from non-controlling interests and higher proceeds from long-term debt,
partially offset by unfavourable variances in short-term borrowings and lower
net borrowings under committed credit facilities classified as long term.
Proceeds from the issuance of preferences shares were also lower year to date
compared to the same period in 2010.
Net repayments of short-term borrowings were $102 million during the second
quarter of 2011 compared to net proceeds from short-term borrowings of $55
million during the same quarter in 2010. Net repayments of short-term borrowings
were $200 million year to date compared to $126 million during the same period
in 2010. The changes in short-term borrowings were driven by the FortisBC Energy
companies due to seasonality differences and timing of repayments using proceeds
from equity injections from the Corporation.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease obligations and net borrowings under committed credit
facilities for the quarter and year to date compared to the same periods last
year are summarized in the following tables.
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30 Quarter Ended Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
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Caribbean Utilities (1) 29 - 29 29 - 29
Other 1 - 1 1 - 1
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Total 30 - 30 30 - 30
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(1) Issued in June 2011, 15-year US$11.25 million 4.85% and 20-year
US$18.75 million 5.10% unsecured notes. The net proceeds are being
used to repay current installments on long-term debt and short-term
borrowings and to finance capital expenditures.
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Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended June 30 Quarter Ended Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
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FortisBC Energy Companies - (1) 1 - (1) 1
Maritime Electric - (15) 15 - (15) 15
Caribbean Utilities (12) (15) 3 (12) (15) 3
Fortis Properties (2) (38) 36 (4) (52) 48
Corporate (1) - (125) 125 - (125) 125
Other (4) (2) (2) (6) (4) (2)
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Total (18) (196) 178 (22) (212) 190
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(1) In April 2010 FHI redeemed in full for cash its $125 million 8%
Capital Securities with proceeds from borrowings under the
Corporation's committed credit facility.
----------------------------------------------------------------------------
Net Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended June 30 Quarter Ended Year-to-Date
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta 5 20 (15) 17 60 (43)
FortisBC Electric 7 21 (14) 7 12 (5)
Newfoundland Power 10 2 8 23 13 10
Corporate 36 143 (107) 26 72 (46)
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Total 58 186 (128) 73 157 (84)
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Borrowings under credit facilities by the utilities are primarily in support of
their capital expenditure programs and/or for working capital requirements.
Repayments are primarily financed through the issuance of long-term debt, cash
from operations and/or equity injections from Fortis. From time to time,
proceeds from preference share, common share and long-term debt issues are used
to repay borrowings under the Corporation's committed credit facility.
Advances of approximately $40 million and $57 million for the quarter and year
to date, respectively, were received from non-controlling interests in the
Waneta Partnership to finance capital expenditures related to the Waneta
Expansion Project.
In June 2011 Fortis issued 9.1 million common shares for gross proceeds of $300
million. The net proceeds of $288 million are being used to repay borrowings
under credit facilities and finance equity injections into the utilities in
western Canada and the Waneta Expansion Project in support of infrastructure
investment, and for general corporate purposes.
In January 2010 Fortis completed a $250 million 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 second quarter of 2011 were $36 million,
net of $15 million in dividends reinvested, compared to $36 million, net of $13
million in dividends reinvested, paid during the same quarter of 2010. Common
share dividends paid year-to-date 2011 were $71 million, net of $31 million in
dividends reinvested, compared to $69 million, net of $28 million in dividends
reinvested, paid year-to-date 2010. The dividend paid per common share for each
of the first and second quarters of 2011 was $0.29 compared to $0.28 for each of
the first and second quarters of 2010. The weighted average number of common
shares outstanding for the quarter and year to date were 177.1 million and 175.8
million, respectively, compared to 172.4 million and 172.0 million,
respectively, for the same periods in 2010.
CONTRACTUAL OBLIGATIONS
Consolidated contractual obligations of Fortis over the next five years and for
periods thereafter, as at June 30, 2011, are outlined in the following table. A
detailed description of the nature of the obligations is provided in the MD&A
for the year ended December 31, 2010 and below, where applicable.
----------------------------------------------------------------------------
Contractual Obligations
(Unaudited) Due Due in Due in Due
As at June 30, 2011 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
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Long-term debt 5,700 318 289 695 4,398
Waneta Partnership promissory
note 72 - - - 72
Brilliant Terminal Station 59 3 5 5 46
Gas purchase contract
obligations (1) 474 269 183 22 -
Power purchase obligations (2)
FortisBC Electric 2,887 44 88 82 2,673
FortisOntario 434 44 98 102 190
Maritime Electric 217 55 79 69 14
Capital cost (3) 470 13 34 38 385
Joint-use asset and share
service agreements 64 4 8 7 45
Office lease - FortisBC
Electric 17 2 3 3 9
Operating lease obligations 120 18 29 27 46
Defined benefit pension funding
contributions (4) 77 33 39 2 3
Other 22 3 8 7 4
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Total 10,613 806 863 1,059 7,885
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(1) Based on index prices as at June 30, 2011
(2) Excludes power purchase obligations of Belize Electricity, due to the
discontinuance of the consolidation method of accounting for the
financial results of 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 (covering non-unionized employees)
December 31, 2013 FortisBC Energy (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 plan at FortisBC Energy, 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 change from that disclosed in the MD&A for the year ended December 31, 2010
except that $20 million of FEVI government loans are now included in long-term
debt obligations due within one year as a result of an expected repayment within
one year.
For a discussion of the nature and amount of the Corporation's consolidated
capital expenditure program, which is not included in the contractual
obligations table above, refer to the "Capital Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to allow the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt issues. To help ensure access to capital, the Corporation targets
a consolidated long-term capital structure containing approximately 40% equity,
including preference shares, and 60% debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own capital
structure in line with the deemed capital structure reflected in the utilities'
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure (Unaudited) As at
June 30, 2011 December 31, 2010
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
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Total debt and capital lease
obligations (net of cash) (1) 5,559 54.5 5,914 58.4
Preference shares (2) 912 8.9 912 9.0
Common shareholders' equity 3,738 36.6 3,305 32.6
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Total (3) 10,209 100.0 10,131 100.0
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(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity
(3) Excludes amounts related to non-controlling interests
The change in the capital structure was driven by the public issuance of $300
million in common shares in June 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 other long-term
assets. Also contributing to the change in the capital structure was net
earnings applicable to common shares, net of dividends, lower short-term
borrowings and higher cash on hand.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
The credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, 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 $519 million in gross capital expenditures by segment for the
first half of 2011 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited)
(1)
Year-to-Date June 30, 2011
($ millions)
----------------------------------------------------------------------------
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Other Regu-
Regu- lated
lated Total Elec-
Elec- Regu- tric Non-
Fortis- tric lated Utili- Regu-
BC Fortis- New- Utili- Utili- ties- lated -
Energy Fortis BC found- ties- ties- Carib- Utili- Fortis
Com- Alberta Elec- land Cana- Cana- bean ty Proper-
panies (2) tric Power dian dian (3) (4) ties Total
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114 171 53 31 19 388 40 82 9 519
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(1) Relates to cash payments to acquire or construct utility capital
assets, income producing properties and intangible assets, as
reflected in the consolidated statement of cash flows. Includes asset
removal and site restoration expenditures, net of salvage proceeds,
for those utilities where such expenditures are permissible in rate
base in 2011. Excludes capitalized amortization and non-cash equity
component of the allowance for funds used during construction.
(2) Includes payments made to 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 were no material changes in the overall expected level, nature and timing
of the Corporation's significant capital projects from those disclosed in the
MD&A for the year ended December 31, 2010, except as described below.
In April 2011 Fortis Properties filed a development application to construct a
12-storey office building in St. John's, Newfoundland, subject to municipal
government approval. The $50 million project will feature 145,000 square feet of
Class A office space and include 262 parking spaces. It is expected to be
completed in the second half of 2013.
Approximately $10 million of the originally estimated forecast project cost for
2011 related to FEI's Customer Care Enhancement Project is expected to be
incurred in the first half of 2012. The total project cost is expected to be
approximately $116 million.
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 currently being
filled and is expected to be available for the upcoming winter heating season.
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
financial results of 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 which may limit
their ability to distribute cash to Fortis. Cash required of Fortis to support
subsidiary capital expenditure programs and finance acquisitions is expected to
be derived from a combination of borrowings under the Corporation's committed
credit facility and proceeds from the issuance of common shares, preference
shares and long-term debt. Depending on the timing of cash payments from the
subsidiaries, borrowings under the Corporation's committed credit facility may
be required from time to time to support the servicing of debt and payment of
dividends.
As at June 30, 2011, management expects consolidated long-term debt maturities
and repayments to average approximately $260 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 $57 million as at June 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 June 30, 2011 and
are expected to remain compliant throughout 2011.
CREDIT FACILITIES
As at June 30, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.5 billion was
unused, including $409 million unused under the Corporation's $600 million
committed revolving credit facility. The credit facilities are syndicated almost
entirely with the seven largest Canadian banks, with no one bank holding more
than 25% of these facilities. Approximately $2.0 billion of the total credit
facilities are committed facilities with maturities between 2012 and 2015.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities (Unaudited) As at
December
Corporate Regulated Fortis June 30, 31,
($ millions) and Other Utilities Properties 2011 2010
----------------------------------------------------------------------------
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Total credit facilities 645 1,436 13 2,094 2,109
Credit facilities
utilized:
Short-term borrowings - (154) (3) (157) (358)
Long-term debt
(including current
portion) (191) (101) - (292) (218)
Letters of credit
outstanding (1) (120) - (121) (124)
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Credit facilities unused 453 1,061 10 1,524 1,409
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As at June 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 $100 million
unsecured committed credit facility, obtaining an extension to the maturity of
the facility to August 2015 from August 2013. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows:
----------------------------------------------------------------------------
Financial Instruments
(Unaudited) As at
June 30, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Waneta Partnership
promissory note 43 41 42 40
Long-term debt, including
current portion (1) 5,700 6,427 5,669 6,431
Preference shares,
classified as debt (2) 320 346 320 344
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(1) Carrying value as at June 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
$612 million as at June 30, 2011 (December 31, 2010 - $615 million).
Excluded from the above table is the $112 million asset as at June 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 June 30, 2011, US$529 million of the US$594 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 other long-term assets, does not
qualify for hedge accounting as Belize Electricity is no longer a
self-sustaining foreign subsidiary of Fortis. As a result, approximately US$65
million of corporately issued debt that previously hedged the former investment
in Belize Electricity is no longer an effective hedge. Effective June 20, 2011,
foreign exchange gains and losses on the translation of the asset associated
with Belize Electricity and the corporately issued US dollar denominated debt
that previously qualified as a hedge of the investment are required to be
recognized in earnings. This change in accounting treatment is not expected to
have a material impact on consolidated earnings of Fortis. As at June 30, 2011,
all of the Corporation's net investments in self-sustaining foreign subsidiaries
were hedged (December 31, 2010 - 99%).
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes.
The following table summarizes the valuation of the Corporation's derivative
financial instruments.
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Derivative Financial Instruments (Unaudited) As at
June 30, 2011 December 31, 2010
Estimated Estimated
Term to Carrying Fair Carrying Fair
Maturity Number of Value ($ Value ($ Value ($ Value ($
Liability (years) Contracts millions) millions) millions) millions)
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Foreign
exchange
forward
contracts less than 1 2 - - - -
Fuel option
contracts less than 1 2 (1) (1) - -
Natural gas
derivatives:
Swaps and
options Up to 4 183 (117) (117) (162) (162)
Gas
purchase
contract
premiums Up to 3 50 (3) (3) (5) (5)
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The foreign exchange forward contracts are held by the FortisBC Energy
companies. During 2010 FEI entered into a foreign exchange forward contract to
hedge the cash flow risk related to approximately US$5 million remaining to be
paid under a contract for the implementation of a customer information system.
FEVI also hedges the cash flow risk related to less than US$1 million remaining
to be paid under a contract for the construction of the LNG storage facility on
Vancouver Island.
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 with electricity rates,
temper gas price volatility on customer rates and reduce the risk of regional
price discrepancies.
The changes in the fair values of the foreign exchange forward contracts, 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 June 30, 2011 and as at
December 31, 2010.
The foreign exchange forward contracts are valued using the present value of
cash flows based on a market foreign exchange rate and the foreign exchange
forward rate curve. The 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
contracts, 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 $121 million, as at June
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 during the
first half of 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 initiated proceedings for
compensation from the GOB for the value of the Corporation's previous investment
in Belize Electricity. 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 GOB has indicated publicly that it does not intend to expropriate BECOL. As
at June 30, 2011, the book value of the Corporation's investment in BECOL was
$150 million.
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") at the above date. 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. 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. During the first half of 2011, DBRS confirmed
its existing credit ratings for Newfoundland Power and Caribbean Utilities and
in July 2011 Moody's Investors Service confirmed its existing credit ratings for
Newfoundland Power and FEI.
Defined Benefit Pension Plan Performance: As at June 30, 2011, the fair value of
the Corporation's consolidated defined benefit pension plan assets was $753
million, up $26 million, or 3.6%, from $727 million as at December 31, 2010.
Labour Relations: The collective agreement between FortisBC Electric and Local
378 of the Canadian Office and Professional Employees Union ("COPE") expired
January 31, 2011. The Company and COPE 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.
CHANGE IN ACCOUNTING TREATMENT
Effective January 1, 2011, as approved by the regulator, the cost of OPEB plans
at Newfoundland Power is being expensed and recovered in customer rates based on
the accrual method of accounting for OPEBs. 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 six
months ended June 30, 2011, operating expenses increased by approximately $2
million and $4 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
timing and 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 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.
The Corporation has developed a three-phase plan to adopt US GAAP effective
January 1, 2012. The following is an overview of the activities under each phase
and their current status.
Phase I - Scoping and Diagnostics: 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 following 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 involves the implementation of
all financial reporting, systems and internal control changes required by the
Corporation to prepare and file its consolidated financial statements based on
US GAAP beginning in 2012 and the communication of associated impacts.
The Corporation will prepare and file, in accordance with Canadian GAAP, its
annual audited consolidated financial statements for the year ending December
31, 2011. The Corporation intends to voluntarily prepare and file, in accordance
with US GAAP, its annual audited consolidated financial statements for the year
ending December 31, 2011 and the comparative period. The voluntary filing is
expected to be completed prior to 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 has commenced and will conclude when the Corporation prepares and
files, in accordance with US GAAP, its annual audited consolidated financial
statements for the year ending December 31, 2012.
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 as follows:
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, with the opening unamortized balances related to
past service costs, actuarial gains and losses and transitional obligations
recognized on the balance sheet as a component of accumulated other
comprehensive income. Changes to past service costs, actuarial gains and losses
and transitional obligations which are not immediately recognized as components
of net pension expense are required to be recognized in other comprehensive
income. Entities with activities subject to rate regulation would recognize the
opening unamortized balances as regulatory assets or liabilities for recovery
from, or refund to, customers in future rates, with subsequent changes to these
balances recognized as net 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, with the
exception of FortisAlberta as discussed below, will recognize the unfunded or
funded status of its defined benefit plans on the balance sheet with the
above-noted unamortized balances recognized as regulatory assets or liabilities.
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.
Additional differences between Canadian GAAP and US GAAP in the accounting for
defined benefit plans include the determination of the measurement date and the
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. US GAAP requires the entity's fiscal year end to be used as the
measurement date. Canadian GAAP allows for the use of an attribution period that
extends beyond the date when the credited service period ends, under specific
circumstances, for defined benefit pension plans. US GAAP allows for the use of
an attribution period up to the date when credited service ends for defined
benefit pension plans.
The above differences will impact the calculation of the Corporation's
consolidated benefit obligation which will be mostly offset by a corresponding
change to regulatory assets or liabilities.
The impact of adopting US GAAP with respect to accounting for pensions and OPEBs
for regulated and non-regulated entities is not expected to have a material
impact on the Corporation's consolidated earnings.
Brilliant Power Purchase Agreement ("BPPA"): FortisBC Electric expects that the
BPPA will qualify for capital lease accounting 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 for
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 recognizing Brilliant as a capital lease
retrospectively under US GAAP is the recognition of a capital lease asset with
an offsetting obligation under capital lease for an equivalent amount. Each
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 regulator. 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 have an effect on the Corporation's
consolidated earnings.
Reclassification of preference shares: Currently, under Canadian GAAP, the
Corporation's First Preference Shares, Series C and Series E 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 the Series C and Series E First
Preference Shares from long-term debt to shareholders' equity. The associated
dividends 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 substantially 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 substantially enacted tax
rates related to the calculation of the Part VI.1 tax deduction associated with
preference share dividends. The retroactive adjustment to recognize the Part
VI.1 tax deduction based on enacted corporate income tax rates under US GAAP
will result in a reduction in opening retained earnings and annual earnings
thereafter. However, the amount of the adjustments are not expected to be
material and will reverse once pending Canadian federal legislation is passed
resulting in the enactment of the proposed corporate income tax rate changes.
The above items do not represent a complete list of expected differences between
US GAAP and Canadian GAAP. Analysis remains ongoing and additional areas where
the Corporation's financial statements may be materially impacted could be
identified prior to the Corporation's voluntary preparation and filing, in
accordance with US GAAP, of its annual audited consolidated financial statements
for the year ending December 31, 2011. Any additional areas where significant
adjustments may be required will be disclosed as they are determined. As
previously indicated, no material adjustments to the Corporation's consolidated
earnings under US GAAP are currently expected due to the Corporation's continued
ability to apply rate-regulated accounting policies.
The quantification and reconciliation of the Corporation's consolidated
financial statements from Canadian GAAP to US GAAP for 2010 is scheduled for
completion by September 30, 2011. The quantification and reconciliation of the
Corporation's consolidated financial statements from Canadian GAAP to US GAAP
for 2011 interim and annual reporting periods is scheduled for completion 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 during the first half of 2011 from
those disclosed in the MD&A for the year ended December 31, 2010.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with ordinary course business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations. There were no material changes in the
Corporation's contingent liabilities from those disclosed in the MD&A for the
year ended December 31, 2010.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended September 30, 2009 through June 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.
----------------------------------------------------------------------------
Summary of Quarterly Results
(Unaudited)
Net Earnings
Attributable
to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
September 30, 2009 665 36 0.21 0.21
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A summary of the past eight quarters reflects the Corporation's continued
organic growth and growth from acquisitions, as well as the seasonality
associated with its businesses. Interim results will fluctuate due to the
seasonal nature of gas and electricity demand and water flows, as well as the
timing and recognition of regulatory decisions. Revenue is also affected by the
cost of fuel and purchased power and the commodity 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 the financial results of Belize
Electricity. For further information refer to the "Corporate Overview" section
of this MD&A. Financial results for the third quarter ended September 30, 2010
reflected the favourable cumulative retroactive impact associated with a
2010-2011 regulatory rate decision for FortisAlberta. 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. To a lesser degree, financial
results from October 2009 have been favourably impacted by the acquisition of
Algoma Power.
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. A discussion of the variances between the financial results for
the second quarter of 2011 and the second quarter of 2010 is provided in the
"Financial Highlights" section of this MD&A.
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 growth in 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,
partially offset by the timing of and regulator-approved increase in certain
operating expenses at the FortisBC Energy companies. Earnings also increased due
to lower corporate business development costs and higher non-regulated
hydroelectric generation in Belize during the first quarter of 2011.
December 2010/December 2009: Net earnings attributable to common equity
shareholders were $85 million, or $0.49 per common share, for the fourth quarter
of 2010 compared to earnings of $81 million, or $0.48 per common share, for the
fourth quarter of 2009. The increase was mainly due to improved performance at
Canadian Regulated Electric Utilities, non-regulated hydroelectric generation
operations in Belize and lower effective corporate income taxes at Fortis
Properties, partially offset by lower earnings from the FortisBC Energy
companies and Caribbean Regulated Electric Utilities. Improved performance at
Canadian Regulated Electric Utilities was driven by overall growth in electrical
infrastructure investment, combined with customer growth at FortisAlberta and
the higher allowed ROE at FortisBC Electric. Earnings were lower quarter over
quarter at the FortisBC Energy companies, as a result of higher
regulator-approved operating expenses and the timing of the recognition of these
increased expenses, and at Caribbean Regulated Electric Utilities, mainly due to
lower electricity sales associated with cooler-than-normal temperatures
experienced in the region and the inability of Belize Electricity to earn a fair
and reasonable return due to regulatory challenges. Earnings for the fourth
quarter of 2009 were reduced by $5 million related to the expensing of the
project cost overrun associated with the conversion of Whistler customer
appliances from propane to natural gas, but were favourably impacted by a
one-time $3 million tax adjustment at FortisOntario.
September 2010/September 2009: Net earnings attributable to common equity
shareholders were $45 million, or $0.26 per common share, for the third quarter
of 2010 compared to earnings of $36 million, or $0.21 per common share, for the
third quarter of 2009. The increase in earnings was mainly due to improved
performance at the regulated electric utilities in western Canada and
non-regulated hydroelectric generation operations, partially offset by a higher
loss incurred at the FortisBC Energy companies and higher corporate expenses.
Improved performance at the regulated electric utilities in western Canada was
due to higher allowed ROEs and/or equity component of capital structure, growth
in electrical infrastructure investment combined with an increase in the number
of customers at FortisAlberta, partially offset by a weather-related decrease in
electricity sales at FortisBC Electric and lower net transmission revenue at
FortisAlberta. The increase in earnings' contribution from non-regulated
hydroelectric generation operations was the result of increased production in
Belize, driven by higher rainfall and the commissioning of the Vaca
hydroelectric generating facility in March 2010, and lower finance charges. The
higher loss at the FortisBC Energy companies quarter over quarter largely
related to increased operating and maintenance expenses at FEI that were
approved by the BCUC as part of the recent NSA. The loss in the third quarter of
2010, however, was reduced by $4 million (after tax) related to the
BCUC-approved reversal of most of the project cost overrun previously expensed
in the fourth quarter of 2009 associated with the conversion of Whistler
customer appliances from propane to natural gas. The increase in corporate
expenses was associated with higher preference share dividends, partially offset
by lower finance charges.
SUBSEQUENT EVENTS
On July 11, 2011, the Board of Directors of Central Vermont Public Service
Corporation ("CVPS") determined that the unsolicited acquisition proposal from
Gaz Metro Limited Partnership was a "Superior Proposal", as that term is defined
in the Merger Agreement between Fortis and CVPS announced on May 30, 2011 (the
"Merger Agreement") and that 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.
On July 15, 2011, the underwriters of the Corporation's June 2011 $300 million
public offering of 9.1 million common shares exercised their over-allotment
option and purchased an additional 1.24 million common shares of Fortis for
gross proceeds of approximately $41 million.
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 August 2, 2011, the Corporation had issued and outstanding 186.3 million
common shares; 5.0 million First Preference Shares, Series C; 8.0 million First
Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2
million First Preference Shares, Series G; and 10.0 million First Preference
Shares, Series H. Only the common shares of the Corporation have voting rights.
The number of common shares of Fortis that would be issued if all outstanding
stock options, convertible debt and First Preference Shares, Series C and E were
converted as at August 2, 2011 is as follows:
----------------------------------------------------------------------------
Conversion of Securities into Common Shares (Unaudited)
As at August 2, 2011 Number of
Common Shares
Security (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options 4.9
Convertible Debt 1.4
First Preference Shares, Series C 4.2
First Preference Shares, Series E 6.7
----------------------------------------------------------------------------
Total 17.2
----------------------------------------------------------------------------
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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 six months ended June 30, 2011 and 2010
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
June 30, December 31,
2011 2010
----------------------------------------------------------------------------
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ASSETS
Current assets
Cash and cash equivalents $ 298 $ 109
Accounts receivable (Note 20) 589 655
Prepaid expenses 23 17
Regulatory assets (Note 5) 196 241
Inventories (Note 6) 108 168
Future income taxes 21 14
------------------------------
1,235 1,204
Assets held for sale (Note 7) 45 45
Other assets (Note 8) 277 168
Regulatory assets (Note 5) 889 831
Future income taxes 13 16
Utility capital assets 8,286 8,202
Income producing properties 557 560
Intangible assets 327 324
Goodwill 1,548 1,553
------------------------------
$ 13,177 $ 12,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 20) $ 157 $ 358
Accounts payable and accrued charges 847 953
Dividends payable 57 54
Income taxes payable 39 30
Regulatory liabilities (Note 5) 71 60
Current installments of long-term debt and
capital lease obligations (Note 9) 321 56
Future income taxes 3 6
------------------------------
1,495 1,517
Other liabilities 313 308
Regulatory liabilities (Note 5) 522 467
Future income taxes 640 623
Long-term debt and capital lease obligations
(Note 9) 5,379 5,609
Preference shares 320 320
------------------------------
8,669 8,844
------------------------------
Shareholders' equity
Common shares (Note 10) 2,915 2,578
Preference shares 592 592
Contributed surplus 13 12
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (Note 12) (69) (94)
Retained earnings 874 804
------------------------------
4,330 3,897
Non-controlling interests 178 162
------------------------------
4,508 4,059
------------------------------
$ 13,177 $ 12,903
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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 June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 850 $ 835 $ 2,014 $ 1,908
--------------------------------------------
Expenses
Energy supply costs 358 367 961 919
Operating 213 202 425 404
Amortization 103 97 206 191
--------------------------------------------
674 666 1,592 1,514
--------------------------------------------
Operating income 176 169 422 394
Finance charges (Note 14) 92 88 183 178
--------------------------------------------
Earnings before corporate taxes 84 81 239 216
Corporate taxes (Note 15) 15 15 45 43
--------------------------------------------
Net earnings $ 69 $ 66 $ 194 $ 173
--------------------------------------------
--------------------------------------------
Net earnings attributable to:
Non-controlling interests $ 3 $ 3 $ 4 $ 4
Preference equity shareholders 8 8 15 14
Common equity shareholders 58 55 175 155
--------------------------------------------
$ 69 $ 66 $ 194 $ 173
--------------------------------------------
--------------------------------------------
Earnings per common share (Note
10)
Basic $ 0.33 $ 0.32 $ 1.00 $ 0.90
Diluted $ 0.33 $ 0.32 $ 0.99 $ 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at beginning of period $ 870 $ 767 $ 804 $ 763
Net earnings attributable to
common and preference equity
shareholders 66 63 190 169
--------------------------------------------
936 830 994 932
Dividends on common shares (54) (49) (105) (145)
Dividends on preference shares
classified as equity (8) (8) (15) (14)
--------------------------------------------
Balance at end of period $ 874 $ 773 $ 874 $ 773
----------------------------------------------------------------------------
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See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 69 $ 66 $ 194 $ 173
--------------------------------------------
--------------------------------------------
Other comprehensive (loss)
income
Unrealized foreign currency
translation (losses) gains on
net investments in self-
sustaining foreign operations (3) 28 (18) 8
Gains (losses) on hedges of net
investments in self-sustaining
foreign operations 4 (19) 18 (5)
Corporate tax (recovery) expense (1) 3 (3) 1
--------------------------------------------
Unrealized foreign currency
translation gains (losses), net
of hedging activities and tax
(Note 12) - 12 (3) 4
--------------------------------------------
Comprehensive income $ 69 $ 78 $ 191 $ 177
--------------------------------------------
--------------------------------------------
Comprehensive income
attributable to:
Non-controlling interests $ 3 $ 3 $ 4 $ 4
Preference equity shareholders 8 8 15 14
Common equity shareholders 58 67 172 159
--------------------------------------------
$ 69 $ 78 $ 191 $ 177
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See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2011 2010 2011 2010
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(Note (Note
23) 23)
Operating activities
Net earnings $ 69 $ 66 $ 194 $ 173
Items not affecting cash:
Amortization - utility
capital assets and income
producing properties 94 87 188 170
Amortization - intangible
assets 10 9 20 20
Amortization - other (1) 1 (2) 1
Future income taxes 1 2 (1) (1)
Other 7 - 5 2
Change in long-term regulatory
assets and liabilities - (4) 18 -
--------------------------------------------
180 161 422 365
Change in non-cash operating
working capital 48 43 105 40
--------------------------------------------
228 204 527 405
--------------------------------------------
Investing activities
Change in other assets and other
liabilities (2) 1 (5) 3
Capital expenditures - utility
capital assets (268) (234) (487) (413)
Capital expenditures - income
producing properties (6) (3) (9) (9)
Capital expenditures -
intangible assets (12) (7) (23) (10)
Contributions in aid of
construction 19 14 31 24
Proceeds on sale of utility
capital assets and income
producing properties 1 - 6 -
--------------------------------------------
(268) (229) (487) (405)
--------------------------------------------
Financing activities
Change in short-term borrowings (102) 55 (200) (126)
Proceeds from long-term debt,
net of issue costs 30 - 30 -
Repayments of long-term debt and
capital lease obligations (18) (196) (22) (212)
Net borrowings under committed
credit facilities 58 186 73 157
Advances from non-controlling
interests 40 1 57 1
Issue of common shares, net of
costs and dividends reinvested 290 3 301 11
Issue of preference shares, net
of costs - - - 242
Dividends
Common shares, net of
dividends reinvested (36) (36) (71) (69)
Preference shares (8) (8) (15) (14)
Subsidiary dividends paid to
non-controlling interests (2) (2) (4) (4)
--------------------------------------------
252 3 149 (14)
--------------------------------------------
Effect of exchange rate changes
on cash and cash equivalents - 1 - -
--------------------------------------------
Change in cash and cash
equivalents 212 (21) 189 (14)
Cash and cash equivalents,
beginning of period 86 92 109 85
--------------------------------------------
Cash and cash equivalents, end
of period $ 298 $ 71 $ 298 $ 71
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Supplementary Information to Consolidated Statements of Cash Flows (Note
17)
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 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 the financial results of Belize Electricity (Note 8).
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New York
State.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 21 hotels, comprised of more than 4,100
rooms, in eight Canadian provinces and approximately 2.7 million square feet of
commercial office and retail space primarily in Atlantic Canada.
CORPORATE AND OTHER
The Corporate and Other segment includes Fortis net corporate expenses, net
expenses of non-regulated FortisBC Holdings Inc. ("FHI") (formerly Terasen Inc.)
corporate-related activities, and the financial results of FHI's 30% ownership
interest in CustomerWorks Limited Partnership and of FHI's non-regulated wholly
owned subsidiary FortisBC Alternative Energy Services Inc. (formerly Terasen
Energy Services Inc.).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements do not include all of the
information and disclosures required in the annual consolidated financial
statements and should be read in conjunction with the Corporation's 2010 annual
audited consolidated financial statements. Interim results will fluctuate due to
the seasonal nature of gas and electricity demand and water flows, as well as
the timing and recognition of regulatory decisions. Because of natural gas
consumption patterns, most of the 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
OPEBs. 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 six months ended June 30, 2011, operating
expenses increased by approximately $2 million and $4 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 timing and adoption of a rate-regulated
accounting standard by the International Accounting Standards Board ("IASB"). As
a qualifying entity with rate-regulated activities, Fortis has elected to opt
for the one-year deferral and, therefore, will continue to prepare its
consolidated financial statements in accordance with Part V of the Canadian
Institute of Chartered Accountants Handbook for all interim and annual periods
ending on or before December 31, 2011.
Due to continued uncertainty around the timing and adoption of a rate-regulated
accounting standard by the IASB, Fortis has evaluated the option of adopting
United States generally accepted accounting principles ("US GAAP"), as opposed
to IFRS, 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. Therefore, 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: (a) January 1, 2015; or (b) the date on which the
Corporation ceases to have activities subject to rate regulation.
The Corporation's application of Canadian GAAP currently relies 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 six months
ended June 30, 2011.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A detailed description of the nature of the Corporation's regulatory
assets and liabilities is provided in Note 5 to the Corporation's 2010 annual
audited consolidated financial statements.
As at
June 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Regulatory assets
Future income taxes 595 568
Rate stabilization accounts - FortisBC Energy
companies 101 146
Rate stabilization accounts - electric
utilities 56 44
Regulatory OPEB plan assets 65 66
Replacement energy deferral - Point Lepreau
(1) 47 44
Deferred energy management costs 27 23
Deferred losses on disposal of utility capital
assets 21 16
Alberta Electric System Operator ("AESO")
charges deferral 20 19
2010 accrued distribution revenue adjustment
rider 18 36
Income taxes recoverable on OPEB plans 18 18
Deferred operating costs 16 11
Deferred development costs for capital 11 11
Deferred costs - smart meters 8 8
Deferred lease costs 6 6
Deferred pension costs 4 5
Other regulatory assets 72 51
----------------------------------------------------------------------------
Total regulatory assets 1,085 1,072
Less: current portion (196) (241)
----------------------------------------------------------------------------
Long-term regulatory assets 889 831
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
June 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Regulatory liabilities
Asset removal and site restoration provision 348 339
Rate stabilization accounts - FortisBC
Energy companies 138 60
Rate stabilization accounts - electric
utilities 28 45
AESO charges deferral 12 9
Performance-based rate-setting incentive
liabilities 8 8
Deferred interest 8 7
Southern Crossing Pipeline deferral 7 5
Unrecognized net gains on disposal of
utility capital assets 6 8
2010 FEI revenue surplus 3 7
Unbilled revenue liability - 5
Other regulatory liabilities 35 34
----------------------------------------------------------------------------
Total regulatory liabilities 593 527
Less: current portion (71) (60)
----------------------------------------------------------------------------
Long-term regulatory liabilities 522 467
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. INVENTORIES
As at
June 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Gas in storage 89 148
Materials and supplies 19 20
----------------------------------------------------------------------------
108 168
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the three and six months ended June 30, 2011, inventories of $170 million
and $514 million, respectively, were expensed and reported in energy supply
costs on the interim consolidated statement of earnings ($191 million and $496
million for the three and six months ended June 30, 2010, respectively).
Inventories expensed to operating expenses were $4 million and $7 million for
the three and six months ended June 30, 2011, respectively ($4 million and $7
million for the three and six months ended June 30, 2010, respectively).
Included in inventories expensed to operating expenses was food and beverage
costs at Fortis Properties of $3 million and $5 million for the three and six
months ended June 30, 2011, respectively ($3 million and $5 million for the
three and six months ended June 30, 2010, respectively).
7. ASSETS HELD FOR SALE
The closing of the sale of joint-use poles from Newfoundland Power to Bell
Aliant Inc. (the "Purchaser") is subject to certain closing conditions,
including approval by the Newfoundland and Labrador Board of Commissioners of
Public Utilities ("PUB"), which were to be met by June 30, 2011 or either party
could choose to terminate the new support structure arrangements. Newfoundland
Power filed an application with the PUB in February 2011 seeking approval for
the proposed sale. On July 22, 2011, the PUB issued an order that denied
Newfoundland Power's application requesting approval of the proposed sale. The
PUB indicated that there was lack of evidence to support the customer benefits
of this transaction. The Company is presently reviewing the order and its
options, including whether to appeal the PUB decision or file further evidence
to support the PUB's reconsideration of the proposed sale. The purchase price
continues to be held in escrow and Newfoundland Power is negotiating with the
Purchaser to facilitate the successful completion of the transaction. In the
event of termination of the sale, the rights and recourses under the original
Joint-Use Facilities Partnership Agreement will remain in effect for both
parties.
8. OTHER ASSETS
As at
June 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Deferred pension costs 138 140
Other asset - Belize Electricity 112 -
Long-term accounts receivable 9 9
Other 18 19
----------------------------------------------------------------------------
277 168
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a result of no longer exercising control over the operations of Belize
Electricity, Fortis discontinued the consolidation method of accounting for the
financial results of the Company, effective June 20, 2011. The book value of
Corporation's previously 70% controlled foreign net investment in
self-sustaining Belize Electricity has been recorded in other assets. The asset
is denominated in US dollars and has been translated at the exchange rate
prevailing at the balance sheet date. Effective June 20, 2011, the former
investment in Belize Electricity does not qualify for hedge accounting and, as a
result, from June 20, 2011, foreign exchange gains and losses on the translation
of the asset are required to be recognized in earnings. As at June 20, 2011,
approximately $28 million of unrealized foreign currency translation losses,
related to the Corporation's previous foreign net investment in self-sustaining
Belize Electricity, were reclassified to other assets from accumulated other
comprehensive loss (Note 12).
9. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at
June 30, December 31,
($ millions) 2011 2010
----------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,449 5,489
Long-term classification of committed credit
facilities (Note 20) 292 218
Deferred debt financing costs (41) (42)
----------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,700 5,665
Less: Current installments of long-term debt
and capital lease obligations (321) (56)
----------------------------------------------------------------------------
5,379 5,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value.
As at
Issued and Outstanding June 30, 2011 December 31, 2010
Number of Number of
Shares Shares
(in Amount (in Amount
thousands) ($ millions) thousands) ($ millions)
----------------------------------------------------------------------------
Common shares 185,059 2,915 174,393 2,578
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
June 30, 2011 June 30, 2011
Number of Number of
Shares Shares
(in Amount (in Amount
thousands) ($ millions) thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning of
period 175,422 2,607 174,393 2,578
Public offering 9,100 291 9,100 291
Dividend Reinvestment
Plan 454 15 969 32
Consumer Share
Purchase Plan 11 - 24 1
Stock Option Plans 72 2 573 13
----------------------------------------------------------------------------
Balance, end of period 185,059 2,915 185,059 2,915
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In June 2011 Fortis issued 9.1 million common shares for $33.00 per common
share. The common share issue resulted in gross proceeds of approximately $300
million, or approximately $291 million net of after-tax expenses.
Earnings per Common Share
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding.
Diluted EPS is calculated using the treasury stock method for options and the
"if-converted" method for convertible securities.
EPS were as follows:
Quarter Ended June 30
2011 2010
--------------------------------------------------------------
Weighted Weighted
Average Average
Earnings Shares Earnings Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
----------------------------------------------------------------------------
Basic EPS 58 177.1 $ 0.33 55 172.4 $ 0.32
Effect of
potential
dilutive
securities:
Stock
Options - 1.2 - 0.9
Preference
Shares
(Note 14) 4 10.1 4 11.9
Convertible
Debentures 1 1.4 1 1.4
----------------------------------------------------------------------------
63 189.8 60 186.6
Deduct anti-
dilutive
impacts:
Preference
Shares (4) (10.1) (4) (11.9)
Convertible
Debentures (1) (1.4) (1) (1.4)
----------------------------------------------------------------------------
Diluted EPS 58 178.3 $ 0.33 55 173.3 $ 0.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date June 30
2011 2010
--------------------------------------------------------------
Weighted Weighted
Average Average
Earnings Shares Earnings Shares
($ millions)(in millions) EPS($ millions)(in millions) EPS
----------------------------------------------------------------------------
Basic EPS 175 175.8 $ 1.00 155 172.0 $ 0.90
Effect of
potential
dilutive
securities:
Stock
Options - 1.2 - 0.9
Preference
Shares
(Note 14) 8 10.1 8 11.9
Convertible
Debentures 1 1.4 1 1.4
----------------------------------------------------------------------------
184 188.5 164 186.2
Deduct anti-
dilutive
impacts:
Preference
Shares (8) (10.1) - -
----------------------------------------------------------------------------
Diluted EPS 176 178.4 $ 0.99 164 186.2 $ 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 the achievement of payment requirements. In March 2011 37,079 PSUs
were paid out to the President and CEO of the Corporation at $33.11 per PSU, for
a total of approximately $1.2 million.
The payout was made upon the three-year maturation period in respect of the PSU
grant made in February 2008 and the President and CEO satisfying the payment
requirements, as determined by the Human Resources Committee of the Board of
Directors.
In March 2011 the Corporation granted 828,512 options to purchase common shares
under its 2006 Stock Option Plan at the five-day volume weighted average trading
price of $32.95 immediately preceding the date of grant. The options vest evenly
over a four-year period on each anniversary of the date of grant. The options
expire seven years after the date of grant. The fair value of each option
granted was $4.57 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.68
Expected volatility (%) 23.1
Risk-free interest rate (%) 2.00
Weighted average expected life (years) 4.5
As at June 30, 2011, 4.9 million stock options were outstanding and 2.8 million
stock options were vested.
12. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, and gains and losses on
discontinued cash flow hedging activities as described in Note 3 to the
Corporation's 2010 annual audited consolidated financial statements.
Quarter Ended June 30
2011 2010
----------------------------------------------------
Opening Ending Opening Ending
balance Net balance balance Net balance
($ millions) April 1 change June 30 April 1 change June 30
-------------------------------------------------------------------
Unrealized
foreign
currency
translation
(losses)
gains, net of
hedging
activities and
tax (93) 28 (65) (86) 12 (74)
Net losses on
derivative
instruments
previously
discontinued
as cash flow
hedges, net of
tax (4) - (4) (5) - (5)
-------------------------------------------------------------------
Accumulated
other
comprehensive
(loss) income (97) 28 (69) (91) 12 (79)
-------------------------------------------------------------------
-------------------------------------------------------------------
Year-to-Date June 30
2011 2010
----------------------------------------------------
Opening Ending Opening Ending
balance Net balance balance Net balance
($ millions) January 1 change June 30 January 1 change June 30
-------------------------------------------------------------------
Unrealized
foreign
currency
translation
(losses)
gains, net of
hedging
activities and
tax (90) 25 (65) (78) 4 (74)
Net losses on
derivative
instruments
previously
discontinued
as cash flow
hedges, net of
tax (4) - (4) (5) - (5)
-------------------------------------------------------------------
Accumulated
other
comprehensive
(loss) income (94) 25 (69) (83) 4 (79)
-------------------------------------------------------------------
-------------------------------------------------------------------
The net change in accumulated other comprehensive loss for the three and six
months ended June 30, 2011 includes the reclassification of approximately $28
million of unrealized foreign currency translation losses, related to the
Corporation's previous foreign net investment in self-sustaining Belize
Electricity, to other assets from accumulated other comprehensive loss as at
June 30, 2011 (Note 8). As at June 20, 2011, unrealized after-tax foreign
currency translation gains of approximately $11 million on 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 $15 million for the
quarter ended June 30, 2011 ($9 million for the quarter ended June 30, 2010) and
$30 million year-to-date June 30, 2011 ($18 million year-to-date June 30, 2010).
The cost of providing the defined contribution arrangements and group RRSPs for
the quarter ended June 30, 2011 was $4 million ($3 million for the quarter ended
June 30, 2010) and $8 million year-to-date June 30, 2011 ($7 million
year-to-date June 30, 2010).
14. FINANCE CHARGES
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2011 2010 2011 2010
--------------------------------------------------------------------------
Interest - Long-term debt and
capital lease
obligations 88 88 179 176
- Short-term borrowings
and other 5 1 9 3
Interest charged during
construction (5) (5) (13) (9)
Dividends on preference shares
classified as debt (Note 10) 4 4 8 8
--------------------------------------------------------------------------
92 88 183 178
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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
June 30 June 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 26 26 73 69
Preference share dividends 2 2 3 3
Difference between Canadian statutory rate
and rates applicable to foreign
subsidiaries (6) (5) (8) (7)
Difference in Canadian provincial
statutory rates applicable to
subsidiaries in different Canadian
jurisdictions 1 (2) (5) (6)
Items capitalized for accounting purposes
but expensed for income tax purposes (12) (8) (28) (20)
Difference between capital cost allowance
and amounts claimed for accounting
purposes 3 1 6 1
Other 1 1 4 3
---------------------------------------------------------------------------
Corporate taxes 15 15 45 43
---------------------------------------------------------------------------
Effective tax rate 17.9% 18.5% 18.8% 19.9%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
As at June 30, 2011, the Corporation had approximately $88 million (December 31,
2010 - $95 million) in non-capital and capital loss carryforwards, of which $18
million (December 31, 2010 - $18 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2014 and 2031.
16. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
Fortis
BC
Energy Total
Compa- Fortis New- Elec- Elec-
Quarter Ended nies - Fortis BC found- Other tric tric
June 30, 2011 Cana- Alber- Elec- land Cana- Cana- Carib-
($ millions) dian ta tric Power dian dian bean(1)
----------------------------------------------------------------------------
Revenue 320 104 64 133 78 379 87
Energy supply
costs 170 - 11 80 47 138 53
Operating
expenses 74 36 21 17 11 85 11
Amortization 27 33 12 11 6 62 8
----------------------------------------------------------------------------
Operating
income 49 35 20 25 14 94 15
Finance
charges 30 16 9 9 5 39 4
Corporate tax
expense
(recovery) 4 - 2 5 3 10 1
----------------------------------------------------------------------------
Net earnings
(loss) 15 19 9 11 6 45 10
Non-
controlling
interests - - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 15 19 9 11 6 45 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 129
Identifiable
assets 4,235 2,239 1,291 1,212 650 5,392 683
----------------------------------------------------------------------------
Total assets 5,143 2,466 1,512 1,212 713 5,903 812
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 65 86 23 17 11 137 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 336 92 59 126 75 352 83
Energy supply
costs 191 - 13 75 46 134 47
Operating
expenses 65 36 19 15 11 81 11
Amortization 28 25 11 12 6 54 9
----------------------------------------------------------------------------
Operating
income 52 31 16 24 12 83 16
Finance
charges 29 14 8 9 5 36 4
Corporate tax
expense
(recovery) 6 - - 4 3 7 2
----------------------------------------------------------------------------
Net earnings
(loss) 17 17 8 11 4 40 10
Non-
controlling
interests - - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 17 17 8 11 4 40 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 143
Identifiable
assets 4,073 1,977 1,189 1,190 626 4,982 820
----------------------------------------------------------------------------
Total assets 4,981 2,204 1,410 1,190 689 5,493 963
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 60 89 37 19 13 158 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
---------------------------------
Corpo- Inter-
Quarter Ended Fortis Fortis rate segment
June 30, 2011 Gene- Proper- and elimina- Consoli-
($ millions) ration(2) ties Other tions dated
----------------------------------------------------------------------
Revenue 7 60 8 (11) 850
Energy supply
costs 1 - - (4) 358
Operating
expenses 1 40 3 (1) 213
Amortization 1 4 1 - 103
----------------------------------------------------------------------
Operating
income 4 16 4 (6) 176
Finance
charges 1 6 18 (6) 92
Corporate tax
expense
(recovery) 1 3 (4) - 15
----------------------------------------------------------------------
Net earnings
(loss) 2 7 (10) - 69
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 8 - 8
----------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 2 7 (18) - 58
----------------------------------------------------------------------
----------------------------------------------------------------------
Goodwill - - - - 1,548
Identifiable
assets 453 580 685 (399) 11,629
----------------------------------------------------------------------
Total assets 453 580 685 (399) 13,177
----------------------------------------------------------------------
----------------------------------------------------------------------
Gross capital
expenditures
(3) 59 6 - - 286
----------------------------------------------------------------------
----------------------------------------------------------------------
Quarter Ended
June 30, 2010
($ millions)
----------------------------------------------------------------------
Revenue 8 60 9 (13) 835
Energy supply
costs 1 - - (6) 367
Operating
expenses 2 39 6 (2) 202
Amortization 1 4 1 - 97
----------------------------------------------------------------------
Operating
income 4 17 2 (5) 169
Finance
charges - 6 18 (5) 88
Corporate tax
expense
(recovery) 1 3 (4) - 15
----------------------------------------------------------------------
Net earnings
(loss) 3 8 (12) - 66
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 8 - 8
----------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 3 8 (20) - 55
----------------------------------------------------------------------
----------------------------------------------------------------------
Goodwill - - - - 1,562
Identifiable
assets 195 581 560 (444) 10,767
----------------------------------------------------------------------
Total assets 195 581 560 (444) 12,329
----------------------------------------------------------------------
----------------------------------------------------------------------
Gross capital
expenditures
(3) 2 4 1 - 244
----------------------------------------------------------------------
----------------------------------------------------------------------
(1) Reflects the discontinuance of the consolidation method of accounting
for the financial results of Belize Electricity from June 20, 2011
(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) 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
Utili-
ties Electric Utilities
---------------------------------------------------------------
Fortis
BC
Energy Total
Compa- Fortis New- Elec- Elec-
Year-to-Date nies - BC found- Other tric tric
June 30, 2011 Cana- Fortis Elec- land Cana- Cana- Carib-
($ millions) dian Alberta tric Power dian dian bean(1)
----------------------------------------------------------------------------
Revenue 895 207 148 316 169 840 162
Energy supply
costs 514 - 34 214 107 355 99
Operating
expenses 151 71 39 37 23 170 22
Amortization 53 66 23 21 12 122 17
----------------------------------------------------------------------------
Operating
income 177 70 52 44 27 193 24
Finance
charges 59 29 18 18 11 76 9
Corporate tax
expense
(recovery) 27 1 6 8 4 19 1
----------------------------------------------------------------------------
Net earnings
(loss) 91 40 28 18 12 98 14
Non-
controlling
interests - - - - - - 4
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 91 40 28 18 12 98 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 129
Identifiable
assets 4,235 2,239 1,291 1,212 650 5,392 683
----------------------------------------------------------------------------
Total assets 5,143 2,466 1,512 1,212 713 5,903 812
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 114 171 53 31 19 274 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2010
($ millions)
----------------------------------------------------------------------------
Revenue 862 180 131 304 157 772 159
Energy supply
costs 496 - 34 206 99 339 92
Operating
expenses 135 71 36 31 22 160 23
Amortization 55 49 21 23 11 104 18
----------------------------------------------------------------------------
Operating
income 176 60 40 44 25 169 26
Finance
charges 56 28 15 18 12 73 9
Corporate tax
expense
(recovery) 30 - 3 8 4 15 2
----------------------------------------------------------------------------
Net earnings
(loss) 90 32 22 18 9 81 15
Non-
controlling
interests - - - - - - 4
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 90 32 22 18 9 81 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 143
Identifiable
assets 4,073 1,977 1,189 1,190 626 4,982 820
----------------------------------------------------------------------------
Total assets 4,981 2,204 1,410 1,190 689 5,493 963
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 110 153 63 36 21 273 36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
---------------------------------
Corpo- Inter-
Year-to-Date Fortis Fortis rate segment
June 30, 2011 Gene- Proper- and elimina- Consoli-
($ millions) ration(2) ties Other tions dated
----------------------------------------------------------------------
Revenue 14 110 15 (22) 2,014
Energy supply
costs 1 - - (8) 961
Operating
expenses 4 77 4 (3) 425
Amortization 2 9 3 - 206
----------------------------------------------------------------------
Operating
income 7 24 8 (11) 422
Finance
charges 1 12 37 (11) 183
Corporate tax
expense
(recovery) 1 3 (6) - 45
----------------------------------------------------------------------
Net earnings
(loss) 5 9 (23) - 194
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 15 - 15
----------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 9 (38) - 175
----------------------------------------------------------------------
----------------------------------------------------------------------
Goodwill - - - - 1,548
Identifiable
assets 453 580 685 (399) 11,629
----------------------------------------------------------------------
Total assets 453 580 685 (399) 13,177
----------------------------------------------------------------------
----------------------------------------------------------------------
Gross capital
expenditures
(3) 82 9 - - 519
----------------------------------------------------------------------
----------------------------------------------------------------------
Year-to-Date
June 30, 2010
($ millions)
----------------------------------------------------------------------
Revenue 13 109 15 (22) 1,908
Energy supply
costs 1 - - (9) 919
Operating
expenses 4 75 10 (3) 404
Amortization 2 8 4 - 191
----------------------------------------------------------------------
Operating
income 6 26 1 (10) 394
Finance
charges - 12 38 (10) 178
Corporate tax
expense
(recovery) 1 4 (9) - 43
----------------------------------------------------------------------
Net earnings
(loss) 5 10 (28) - 173
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 14 - 14
----------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 10 (42) - 155
----------------------------------------------------------------------
----------------------------------------------------------------------
Goodwill - - - - 1,562
Identifiable
assets 195 581 560 (444) 10,767
----------------------------------------------------------------------
Total assets 195 581 560 (444) 12,329
----------------------------------------------------------------------
----------------------------------------------------------------------
Gross capital
expenditures
(3) 3 9 1 - 432
----------------------------------------------------------------------
----------------------------------------------------------------------
(1) Reflects the discontinuance of the consolidation method of accounting
for the financial results of Belize Electricity from June 20, 2011
(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) 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 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 six months ended June 30, 2011 and 2010 were as follows:
Significant Inter-Segment Transactions Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2011 2010 2011 2010
--------------------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities -
Caribbean 3 5 7 8
Sales from Fortis Generation to
Other Canadian Electric Utilities 1 1 1 1
Sales from Newfoundland Power to
Fortis Properties 1 1 2 2
Inter-segment finance charges on
borrowings from:
Corporate to Regulated Electric
Utilities - Canadian 1 - 1 -
Corporate to Regulated Electric
Utilities - Caribbean 1 1 2 2
Corporate to Fortis Generation - 1 1 2
Corporate to Fortis Properties 3 3 6 5
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at June 30
($ millions) 2011 2010
--------------------------------------------------------------------------
Inter-segment borrowings from:
Corporate to Regulated Electric
Utilities - Canadian 50 75
Corporate to Regulated Electric
Utilities - Caribbean 68 59
Corporate to Fortis Generation 50 60
Corporate to Fortis Properties 225 232
Other inter-segment assets 6 18
--------------------------------------------------------------------------
Total inter-segment eliminations 399 444
--------------------------------------------------------------------------
--------------------------------------------------------------------------
17. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2011 2010 2011 2010
--------------------------------------------------------------------------
Interest paid 100 97 181 178
Income taxes paid 21 13 45 37
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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 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
June 30, 2011 December 31, 2010
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash)
(1) 5,559 54.5 5,914 58.4
Preference shares (2) 912 8.9 912 9.0
Common shareholders' equity 3,738 36.6 3,305 32.6
----------------------------------------------------------------------------
Total (3) 10,209 100.0 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 June 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 $57 million as at June 30, 2011
(December 31, 2010 - $58 million). The lenders of the term loan have not
demanded accelerated repayment. The scheduled repayments under the term loan are
being made by Nalcor Energy, a Crown corporation, acting as agent for the
Government of Newfoundland and Labrador with respect to expropriation matters.
For further information refer to Note 30 to the Corporation's 2010 annual
audited consolidated financial statements.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 20.
19. FINANCIAL INSTRUMENTS
Fair Values
There has been no change during the six months ended June 30, 2011 in the
designation of the Corporation's financial instruments from that disclosed in
the Corporation's 2010 annual audited consolidated financial statements.
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as noted in the
following table.
As at
June 30, 2011 December 31, 2010
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Waneta Partnership
promissory note (1) (2) 43 41 42 40
Long-term debt, including
current portion (3) (4) 5,700 6,427 5,669 6,431
Preference shares,
classified as debt (3)
(5) 320 346 320 344
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Included in other long-term 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 June 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
$612 million as at June 30, 2011 (December 31, 2010 - $615 million).
Excluded from the above table is the $112 million asset as at June 30, 2011
related to the Corporation's previous investment in Belize Electricity. The fair
value of this financial asset is not determinable at this time.
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Expansion Limited Partnership promissory note, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a market credit risk
premium equal to that of issuers of similar credit quality. Since, the
Corporation does not intend to settle the long-term debt or promissory note
prior to maturity, the fair value estimate does not represent an actual
liability and, therefore, does not include exchange or settlement costs. The
fair value of the Corporation's preference shares is determined using quoted
market prices.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes. The following table summarizes the valuation of the
Corporation's consolidated derivative financial instruments.
As at
June 30, 2011 December 31, 2010
Estimated Estimated
Term to Carrying Fair Carrying Fair
Maturity Number of Value ($ Value ($ Value ($ Value ($
Liability (years) Contracts millions) millions) millions) millions)
----------------------------------------------------------------------------
Foreign
exchange
forward
contracts less than
(1) (2) 1 2 - - - -
Fuel option
contracts less than
(1) (2) 1 2 (1) (1) - -
Natural gas
derivatives:
(1) (2)
Swaps and
options Up to 4 183 (117) (117) (162) (162)
Gas
purchase
contract
premiums Up to 3 50 (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 June 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 June 30,
2011, its gross credit risk exposure was approximately $133 million,
representing the projected value of retailer billings over a 60-day period. The
Company has reduced its exposure to approximately $8 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 June
30, 2011 (March 31, 2011 - $18 million; December 31, 2010 - $16 million; June
30, 2010 - $17 million) was as follows:
As at
June 30, March 31, December 31, June 30,
($ millions) 2011 2011 2010 2010
----------------------------------------------------------------------------
Not past due 488 601 584 442
Past due 0-30 days 67 76 56 49
Past due 31-60 days 20 15 9 14
Past due 61 days and over 14 8 6 11
----------------------------------------------------------------------------
589 700 655 516
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2011, other long-term receivables of $14 million (included in
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
capital and bank credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing
of acquisitions and for general corporate purposes. Depending on the timing of
cash payments from the subsidiaries, borrowings under the Corporation's
committed credit facility may be required from time to time to support the
servicing of debt and payment of dividends. As at June 30, 2011, average annual
consolidated long-term debt maturities and repayments over the next five years
are expected to be approximately $260 million. The combination of available
credit facilities and relatively low annual debt maturities and repayments will
provide the Corporation and its subsidiaries with flexibility in the timing of
access to capital markets.
As at June 30, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.5 billion was
unused. The credit facilities are syndicated almost entirely with the seven
largest Canadian banks, with no one bank holding more than 25% of these
facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
December
($ millions) Corporate Regulated Fortis June 30, 31,
and Other Utilities Properties 2011 2010
----------------------------------------------------------------------------
Total credit
facilities 645 1,436 13 2,094 2,109
Credit facilities
utilized:
Short-term
borrowings - (154) (3) (157) (358)
Long-term debt (Note
9) (1) (191) (101) - (292) (218)
Letters of credit
outstanding (1) (120) - (121) (124)
----------------------------------------------------------------------------
Credit facilities
unused 453 1,061 10 1,524 1,409
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As at June 30, 2011, credit facility borrowings classified as long-
term included $246 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 June 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 $100 million
unsecured committed credit facility obtaining an extension to the maturity of
the facility to August 2015 from August 2013. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
June 30, 2011, the Corporation's credit ratings were as follows:
Standard & Poor's A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
The credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at June 30, 2011.
Financial Liabilities Due Due in Due in Due
within 1 years 2 years 4 after 5
($ millions) year and 3 and 5 years Total
---------------------------------------------------------------------------
Short-term borrowings 157 - - - 157
Trade and other accounts
payable 726 - - - 726
Natural gas derivatives (1) 70 38 3 - 111
Fuel option contracts (2) 1 - - - 1
Foreign exchange forward
contracts (3) 5 - - - 5
Dividends payable 57 - - - 57
Customer deposits (4) - 3 1 2 6
Waneta Partnership promissory
note (5) - - - 72 72
Long-term debt, including
current portion (6) 318 289 695 4,398 5,700
Interest obligations on long-
term debt 344 672 592 4,901 6,509
Preference shares, classified
as debt - 123 - 197 320
Dividend obligations on
preference shares, classified
as finance charges 17 28 20 2 67
---------------------------------------------------------------------------
1,695 1,153 1,311 9,572 13,731
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Amounts disclosed are on a gross cash flow basis. The derivatives
were recorded in accounts payable at fair value as at June 30, 2011
at $120 million.
(2) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts payable at fair value as at June 30, 2011 at $1
million.
(3) Amounts disclosed are on a gross cash flow basis. The contracts were
recorded in accounts payable at fair value as at June 30, 2011 at
less than $1 million.
(4) Customer deposits were recorded in other long-term liabilities as at
June 30, 2011.
(5) Amounts disclosed are on a gross cash flow basis. The promissory note
was recorded in other long-term liabilities at present value as at
June 30, 2011 at $43 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 Belize Electric Company Limited is the US
dollar.
As at June 30, 2011, US$529 million of the US$594 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 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,
approximately US$65 million of corporately issued debt that previously hedged
the former investment in Belize Electricity is no longer 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. This change in accounting treatment
is not expected to have a material impact on consolidated earnings of Fortis. As
at June 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
storage facility, respectively, expose the utilities to fluctuations in the US
dollar-to-Canadian dollar exchange rate. FEI and FEVI have entered into foreign
exchange forward contracts to hedge this exposure and any increase or decrease
in the fair value of the foreign exchange forward contracts is deferred for
recovery from, or refund to, customers in future rates, subject to regulatory
approval.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk
associated with short-term borrowings and floating-rate debt. The Corporation
and its subsidiaries may enter into interest rate swap agreements to help reduce
this risk.
The FortisBC Energy companies and FortisBC Electric have regulatory approval to
defer any increase or decrease in interest expense resulting from fluctuations
in interest rates associated with variable-rate debt for recovery from, or
refund to, customers in future rates.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price risk associated
with changes in the market price of natural gas. This risk is minimized 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 with
electricity rates, temper gas price volatility on customer rates and reduce the
risk of regional price discrepancies. On an annual basis, FEI and FEVI each file
a Price Risk-Management Plan ("PRMP") that seeks approval for the natural gas
commodity hedging plan for the next three years for FEI and the next five years
for FEVI. During the third quarter of 2010, the BCUC denied the PRMP application
filed by the FortisBC Energy companies earlier in 2010 and directed the
Companies to undertake a review of the primary objectives of the PRMP. In
January 2011 the FortisBC Energy companies reviewed the PRMP objectives with the
BCUC related to their gas commodity hedging plan and FEI submitted a 2011-2014
PRMP. In June 2011 FEVI filed a 2012-2013 hedging request application. In July
2011 the BCUC denied FEI's 2011-2014 PRMP with the exception of certain elements
related to basis swaps. 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 six months ended June 30, 2011, the actuarial valuation of the
defined benefit pension plans at FortisBC Energy, 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 June 30, 2011, has increased by approximately $45
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.
As at June 30, 2011, $20 million of FEVI government loans were reclassified from
utility capital assets to current portion of long-term debt as a result of an
expected repayment within one year.
22. SUBSEQUENT EVENTS
On July 11, 2011, the Board of Directors of Central Vermont Public Service
Corporation ("CVPS") determined that the unsolicited acquisition proposal from
Gaz Metro Limited Partnership was a "Superior Proposal", as that term is defined
in the Merger Agreement between Fortis and CVPS announced on May 30, 2011 (the
"Merger Agreement") and that 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.
On July 15, 2011, the underwriters of the Corporation's June 2011 $300 million
public offering of 9.1 million common shares exercised their over-allotment
option and purchased an additional 1.24 million common shares of Fortis for
gross proceeds of approximately $41 million.
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 six months ended June 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; and (ii) a $13 million and $28 million decrease for
the three and six months ended June 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.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with
total assets of approximately $13 billion and fiscal 2010 revenue totalling
approximately $3.7 billion. The Corporation serves approximately 2,000,000 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 primarily in Atlantic Canada.
The Common Shares, First Preference Shares, Series C; First Preference Shares,
Series E; First Preference Shares, Series F; First Preference Shares, Series G;
and First Preference Shares, Series H of Fortis are traded on the Toronto Stock
Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and
FTS.PR.H, respectively.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2010 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
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