Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved net earnings
attributable to common equity shareholders of $318 million, or $1.75 per common
share, up $33 million, or $0.10 per common share, compared to $285 million, or
$1.65 per common share, for 2010.
Increased investment in energy infrastructure at the utilities in western Canada
and the $11 million after-tax, or $0.06 per common share, fee paid to Fortis in
July 2011, following the termination of the Merger Agreement with Central
Vermont Public Service Corporation, were the primary drivers of earnings growth.
Fortis increased its quarterly common share dividend to 30 cents from 29 cents,
commencing with the first quarter dividend payable on March 1, 2012, which
translates into an annualized dividend of $1.20. Fortis has raised its
annualized dividend to common shareholders for 39 consecutive years, the record
for a public corporation in Canada. The dividend payout ratio was 66% in 2011.
"Our annual capital expenditure program totalled a record $1.2 billion in 2011,"
says Stan Marshall, President and Chief Executive Officer, Fortis Inc. "The
significant investment in energy infrastructure being made by our utilities
should help ensure we continue to meet our obligation to serve customers," he
adds.
The largest capital projects recently completed were the $212 million 1.5
billion-cubic foot liquefied natural gas storage facility on Vancouver Island
and the $110 million Customer Care Enhancement Project, including two new call
centres, at FortisBC's gas utility; the $105 million Okanagan Transmission
Reinforcement Project at FortisBC Electric; and the $126 million Automated
Metering Project at FortisAlberta. Construction of the $900 million 335-megawatt
Waneta Expansion hydroelectric generation facility in British Columbia, which is
scheduled to be completed in spring 2015, is progressing on time and on budget,
with approximately $244 million invested in the project since construction began
in late 2010.
Canadian Regulated Gas Utilities delivered earnings of $139 million, up $9
million from $130 million for 2010. Excluding a favourable one-time $4 million
item in 2010, earnings increased $13 million year over year. Results for 2011
reflected the impact of growth in energy infrastructure investment,
lower-than-expected corporate income taxes, finance charges and amortization
costs, and increased gas transportation volumes to the forestry and mining
sectors, partially offset by lower-than-expected customer additions.
"The majority of our gas customers have benefited from the downward trend in
natural gas commodity prices," says Marshall. "The improving supply and cost
fundamentals of natural gas throughout North America, combined with its positive
environmental attributes, make natural gas an attractive energy supply source
for residential and industrial use and as a fuel for the transportation and
power generation sectors," he explains.
Canadian Regulated Electric Utilities contributed earnings of $179 million, up
$15 million from $164 million for 2010. The increase was driven by improved
results at FortisAlberta and FortisBC Electric. The increase in earnings at
FortisAlberta mainly resulted from growth in energy infrastructure investment,
higher capitalized allowance for funds used during construction ("AFUDC"),
customer growth and higher energy deliveries, and return earned on additional
investment in automated meters, as approved by the regulator, partially offset
by a lower allowed rate of return on common shareholders' equity ("ROE") for
2011. The increase in earnings at FortisBC Electric resulted from growth in
energy infrastructure investment, lower purchased power costs and higher
electricity sales, partially offset by lower capitalized AFUDC.
"FortisAlberta continues to invest significant capital in its electricity
network, which includes more than 100,000 kilometres of distribution lines, with
over $400 million of capital expenditures in 2011 and a similar amount planned
for 2012", says Marshall. "A significant portion of the utility's franchise
territory overlaps with the tight oil and shale gas developments in Alberta,
especially the Bakken, Cardium and Duvernay areas, and our business is
benefiting from building the electricity infrastructure necessary to meet
associated customer growth," he explains.
Significant regulatory processes recently decided or underway at the
Corporation's largest utilities are as follows:
-- The Alberta Utilities Commission ("AUC") issued a decision in December
2011 setting the 2011 allowed ROE for utilities in Alberta at 8.75%,
down from 9.00% for 2010. The decision was recorded on a retroactive
basis in the fourth quarter of 2011 and reduced FortisAlberta's earnings
by approximately $2 million in 2011.
-- At FortisAlberta, a decision on customer rates for 2012 is expected
during the first half of 2012. Interim rates have been approved for the
utility.
-- FortisAlberta filed its performance-based regulation ("PBR") proposal in
July 2011, following the AUC's initiative to apply PBR to all
distribution utilities in Alberta as early as 2013 for a five-year term.
The AUC's decision on PBR is expected in 2012.
-- Newfoundland Power received regulatory approval in December 2011 to
suspend the use of the ROE automatic adjustment formula for 2012,
pending an expected review of the utility's cost of capital in 2012.
Customer rates for 2012 have been set on an interim basis using the 2011
allowed ROE of 8.38%.
-- The allowed ROEs for the FortisBC gas and electric utilities are to be
maintained, pending determinations made in the regulator-initiated
Generic Cost of Capital Proceeding expected to occur in early 2012.
-- Decisions on customer gas and electricity rates for 2012 and 2013 at
FortisBC are expected during 2012. Interim rates have been approved for
the utilities.
Caribbean Regulated Electric Utilities contributed $20 million to earnings
compared to $23 million for 2010. There was no earnings contribution from Belize
Electricity in 2011 due to the expropriation of the Corporation's investment in
the utility in June by the Government of Belize ("GOB"). Earnings contribution
from Belize Electricity during 2010 was approximately $1.5 million. Fortis
submitted its claim for compensation to the GOB in November. Earnings at Fortis
Turks and Caicos decreased year over year, due to higher amortization costs and
operating expenses, partially offset by reduced energy supply costs in 2011
reflecting the use of new, more fuel-efficient generating units. There was no
growth in electricity sales year over year at Caribbean Utilities and Fortis
Turks and Caicos, due to challenging economic conditions in the region and high
fuel prices.
Non-Regulated Fortis Generation contributed $18 million to earnings compared to
$20 million for 2010. The decline in earnings resulted from decreased
hydroelectric production in Belize, due to lower rainfall associated with a
longer dry season in 2011, combined with overall lower interest income.
Fortis Properties delivered earnings of $23 million compared to $26 million for
2010. However, results for 2010 were favourably impacted by lower corporate
income tax rates, which reduced future income taxes. Results for 2011 reflected
lower contribution from the Hospitality Division, driven by lower occupancy at
the Company's hotels in western Canada. Fortis Properties acquired the 160-room,
full-service Hilton Suites Winnipeg Airport hotel for $25 million in October
2011.
Corporate and other expenses were $61 million, $17 million lower than $78
million for 2010. Excluding the $11 million after-tax termination fee, corporate
and other expenses were $6 million lower year over year, as a result of both
decreased business development costs and finance charges.
Earnings for the fourth quarter were $86 million, or $0.46 per common share,
compared to $85 million, or $0.49 per common share, for the same quarter in
2010. Increased earnings at the FortisBC gas utilities, largely due to the same
reasons described above for the improvement in annual earnings, were partially
offset by a decrease in earnings at Newfoundland Power, Other Canadian Regulated
Electric Utilities, Fortis Turks and Caicos and Fortis Properties. The decrease
in earnings at Newfoundland Power reflected a lower allowed ROE and higher
operating expenses, partially offset by reduced energy supply costs in the
fourth quarter of 2011. Lower earnings at Other Canadian Regulated Electric
Utilities were due to decreased electricity sales and higher operating expenses.
Lower earnings at Fortis Turks and Caicos were due to the same reasons described
above for the decrease in annual earnings. Earnings at Fortis Properties during
the fourth quarter of 2010 reflected lower corporate income tax rates, which
reduced future income taxes in that period. An 8% increase in the weighted
average number of common shares outstanding quarter over quarter, largely
associated with the public common equity offering in mid-2011, had the impact of
decreasing earnings per common share.
Fortis and its regulated utilities raised $688 million of long-term capital in
2011. Fortis issued approximately 10.3 million common shares for $341 million,
the proceeds of which were used to repay borrowings under credit facilities and
finance equity injections into the regulated utilities in western Canada and the
non-regulated Waneta Expansion Limited Partnership, in support of infrastructure
investment, and for general corporate purposes. Consolidated long-term debt
totalling $347 million was issued in 2011 at terms ranging from 15 to 50 years
and at rates ranging from 4.25% to 5.118%. In December FortisBC's largest gas
utility issued 30-year $100 million 4.25% unsecured debentures, Maritime
Electric issued 50-year 4.915% $30 million first mortgage bonds and
FortisOntario issued 30-year $52 million 5.118% unsecured notes. Generally,
proceeds of the debt offerings were used to repay borrowings under credit
facilities incurred to finance capital expenditures, to finance future capital
spending and for general corporate purposes. In the case of FortisOntario, the
debt proceeds were used to repay an inter-company loan with Fortis, originally
incurred to support the acquisition of Algoma Power in 2009.
The Corporation's US$40 million convertible debentures were converted into 1.4
million common shares at US$29.11 per share in November 2011.
Newfoundland Power received $46 million of proceeds in October 2011 upon the
sale to Bell Aliant Inc. of 40% of all joint-use poles owned by Newfoundland
Power.
DBRS confirmed the Corporation's debt credit rating at A(low) in September 2011.
Standard and Poor's ("S&P") is expected to complete its annual review of the
Corporation's debt credit rating in the first quarter of 2012. S&P currently
rates the Corporation's debt at A-.
Cash flow from operating activities was $904 million for 2011, up $172 million
from $732 million for 2010, driven by favourable working capital changes and
higher earnings.
"We are focused on completing our $1.3 billion capital expenditure program for
2012," says Marshall. "Over the next five years through 2016, our capital
expenditure program is projected to total $5.5 billion, which should support
continuing growth in earnings and dividends," he adds.
"We remain disciplined and patient in our pursuit of electric and gas utility
acquisitions in the United States and Canada that will add value for Fortis
shareholders," concludes Marshall.
Financial Highlights
For the three and twelve months ended December 31, 2011
Dated February 9, 2012
FORWARD-LOOKING STATEMENT
The following fourth quarter 2011 media release should be read in conjunction
with the Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and
Analysis ("MD&A") and audited consolidated financial statements for the year
ended December 31, 2010 included in the Corporation's 2010 Annual Report.
Financial information in this material has been prepared in accordance with
Canadian generally accepted accounting principles ("Canadian GAAP") and is
presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in this fourth quarter 2011 media
release 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 this fourth quarter 2011 media release includes,
but is not limited to, statements regarding: the expected timing of filing of
regulatory applications and of receipt of regulatory decisions; consolidated
forecast gross capital expenditures for 2012 and in total over the five-year
period 2012 through 2016; the expectation that the Corporation's significant
capital expenditure program should drive growth in earnings and dividends; and
the expected impact of the transition to US generally accepted accounting
principles.
The forecasts and projections that make up the forward-looking information are
based on assumptions which include, but are not limited to: the receipt of
applicable regulatory approvals and requested rate orders; no significant
operational disruptions or environmental liability due to a catastrophic event
or environmental upset caused by severe weather, other acts of nature or other
major events; the expectation that the Corporation will receive compensation
from the Government of Belize ("GOB") for the fair value of the Corporation's
investment in Belize Electricity that was expropriated by the GOB; the
expectation that Belize Electric Company Limited ("BECOL") will not be
expropriated by the GOB; the continued ability to maintain the gas and
electricity systems to ensure their continued performance; no material capital
project and financing cost overrun related to the construction of the Waneta
hydroelectric generation expansion project; no significant decline in capital
spending; no severe and prolonged downturn in economic conditions; sufficient
liquidity and capital resources; the continuation of regulator-approved
mechanisms to flow through the commodity cost of natural gas and energy supply
costs in customer rates; the ability to hedge exposures to fluctuations in
interest rates, foreign exchange rates and fuel 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 and fuel supply; the continuation of and/or
regulatory approval of power supply and capacity purchase contracts; the
continued ability to fund defined benefit pension plans; the absence of
significant changes in government energy plans and environmental laws that may
materially affect the operations and cash flows of the Corporation and its
subsidiaries; maintenance of adequate insurance coverage; the ability to obtain
and maintain licences and permits; retention of existing service areas;
maintenance of information technology infrastructure; favourable relations with
First Nations; favourable labour relations; and sufficient human resources to
deliver service and execute the consolidated capital program. The
forward-looking information is subject to risks, uncertainties and other factors
that could cause actual results to differ materially from historical results or
results anticipated by the forward-looking information.
Factors which could cause results or events to differ from current expectations
include, but are not limited to: regulatory risk; operating and maintenance
risks; risk associated with the amount of compensation to be paid to Fortis for
its investment in Belize Electricity that was expropriated by the GOB; the
timeliness of the receipt of the compensation and the ability of the GOB to pay
the compensation owing to Fortis; risk that the GOB may expropriate BECOL;
capital project budget overrun, completion and financing risk in the
Corporation's non-regulated business; economic conditions; capital resources and
liquidity risk; weather and seasonality; commodity price risk; derivative
financial instruments and hedging; interest rate risk; counterparty risk;
competitiveness of natural gas; natural gas and fuel supply; regulatory approval
of power supply and capacity purchase contracts; defined benefit pension plan
performance and funding requirements; risks related to FortisBC Energy
(Vancouver Island) Inc.; 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 year ended December 31, 2010 and for the three and nine months ended
September 30, 2011, and as otherwise disclosed in this fourth quarter 2011 media
release.
All forward-looking information in this fourth quarter 2011 media release is
qualified in its entirety by the above cautionary statements and, except as
required by law, the Corporation undertakes no obligation to revise or update
any forward-looking information as a result of new information, future events or
otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving
more than 2,000,000 gas and electricity customers. Its regulated holdings
include electric utilities in five Canadian provinces and two Caribbean
countries and a natural gas utility in British Columbia, Canada. Fortis owns
non-regulated generation assets, primarily hydroelectric, across Canada and in
Belize and Upper New York State, and hotels and commercial office and retail
space in Canada. In 2011 the Corporation's electricity distribution systems met
a combined peak demand of 5,045 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 2010
annual audited consolidated financial statements.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably 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.
Under COS regulation, the respective regulatory authority sets customer gas
and/or electricity rates to permit a reasonable opportunity for the utility to
recover, on a timely basis, estimated costs of providing service to customers,
including a fair rate of return on a regulatory deemed or targeted capital
structure applied to an approved regulatory asset value ("rate base").
Generally, the ability of a regulated utility to recover prudently incurred
costs of providing service and to earn the regulator-approved rate of return on
common shareholders' equity ("ROE") and/or rate of return on rate base assets
("ROA") depends on the utility achieving the forecasts established in the
rate-setting processes. As such, earnings of regulated utilities are generally
impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA; (ii)
changes in rate base; (iii) changes in energy sales or gas delivery volumes;
(iv) changes in the number and composition of customers; (v) variances between
actual expenses incurred and forecast expenses used to determine revenue
requirements and set customer rates; and (vi) timing differences within an
annual financial reporting period, between when actual expenses are incurred and
when they are recovered from customers in rates. When forward test years are
used to establish revenue requirements and set base customer rates, these rates
are not adjusted as a result of actual COS being different from that which is
estimated, other than for certain prescribed costs that are eligible to be
deferred on the balance sheet. In addition, the Corporation's regulated
utilities, where applicable, are permitted by their respective regulatory
authority to flow through to customers, without markup, the cost of natural gas,
fuel and/or purchased power through base customer rates and/or the use of rate
stabilization and other mechanisms.
Effective March 1, 2011, the Terasen Gas companies were renamed to operate under
a common brand identity with FortisBC in British Columbia, Canada. As a result,
Terasen Gas Inc. is now FortisBC Energy Inc. ("FEI"), Terasen Gas (Vancouver
Island) Inc. is now FortisBC Energy (Vancouver Island) Inc. ("FEVI") and Terasen
Gas (Whistler) Inc. is now FortisBC Energy (Whistler) Inc. ("FEWI"), and
collectively are referred to as the FortisBC Energy companies.
On June 20, 2011, the Government of Belize ("GOB") enacted legislation leading
to the expropriation of the Corporation's investment in Belize Electricity. As a
result of no longer controlling the operations of the utility, the Corporation
has discontinued the consolidation method of accounting for Belize Electricity,
effective June 20, 2011, and has classified the book value of the previous
investment in the utility as a long-term other asset on the consolidated balance
sheet. As at December 31, 2011, the long-term other asset, including foreign
exchange impacts, totalled $106 million.
In October 2011 Fortis commenced an action in the Belize Supreme Court to
challenge the legality of the expropriation of its investment in Belize
Electricity. Fortis commissioned an independent valuation of its expropriated
investment in Belize Electricity and submitted its claim for compensation to the
GOB in November 2011.
The GOB also commissioned an independent valuation of Belize Electricity and
communicated the results of such valuation in its response to the Corporation's
claim for compensation. The fair value of Belize Electricity determined under
the GOB's valuation is significantly lower than the fair value determined under
the Corporation's valuation. The Corporation is pursuing alternative options for
obtaining fair compensation from the GOB.
Fortis continues to control and consolidate the financial statements of Belize
Electric Company Limited ("BECOL"), the Corporation's indirect wholly owned
non-regulated hydroelectric generation subsidiary in Belize. BECOL generates
hydroelectricity from three plants 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. Assuming normal
hydrological conditions, Belize Electricity purchases BECOL's normalized annual
energy production of 240 gigawatt hours ("GWh") at approximately US$0.10 per
kilowatt hour, which generally is the lowest-cost energy supply source in the
country of Belize. As at December 31, 2011, the book value of the Corporation's
investment in BECOL was $154 million. In October 2011 the GOB purportedly
amended the Constitution of Belize to require majority government ownership of
three public utility providers, including Belize Electricity, but excluding
BECOL.
As at January 31, 2012, Belize Electricity owed BECOL US$7.4 million for overdue
energy purchases, representing almost one-third of BECOL's annual sales to
Belize Electricity. In accordance with long-standing agreements, the GOB
guarantees the payment of Belize Electricity's obligations to BECOL.
SUMMARY FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the fourth quarters and years
ended December 31, 2011 and December 31, 2010 are provided in the following
table.
----------------------------------------------------------------------------
Consolidated Financial Highlights (Unaudited)
Periods Ended December
31 Quarter Annual
($ millions, except for
common share data) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
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Revenue 1,037 1,034 3 3,747 3,657 90
Energy Supply Costs 490 507 (17) 1,697 1,686 11
Operating Expenses 237 228 9 865 822 43
Amortization 108 103 5 419 410 9
Other Income (Expenses),
Net 6 6 - 40 13 27
Finance Charges 90 89 1 370 362 8
Corporate Taxes 23 19 4 80 67 13
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Net Earnings 95 94 1 356 323 33
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Net Earnings
Attributable to:
Non-Controlling
Interests 2 2 - 9 10 (1)
Preference Equity
Shareholders 7 7 - 29 28 1
Common Equity
Shareholders 86 85 1 318 285 33
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Net Earnings 95 94 1 356 323 33
----------------------------------------------------------------------------
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Basic Earnings per
Common Share ($) 0.46 0.49 (0.03) 1.75 1.65 0.10
Diluted Earnings per
Common Share ($) 0.45 0.47 (0.02) 1.74 1.62 0.12
Weighted Average Number
of Common
Shares Outstanding (#
millions) 188.1 173.9 14.2 181.6 172.9 8.7
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Cash Flow from Operating
Activities 227 198 29 904 732 172
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Factors Contributing to Quarterly Revenue Variance
Favourable
-- An increase in gas delivery rates and the base component of electricity
rates at most of the Corporation's Canadian regulated utilities,
consistent with rate decisions, reflecting ongoing investment in energy
infrastructure, forecasted higher regulator-approved expenses
recoverable from customers, and a higher allowed ROE at Algoma Power
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities
-- Growth in the number of customers, mainly at FortisAlberta
-- Higher gas sales
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Lower commodity cost of natural gas charged to customers
-- A rate revenue reduction accrued at FortisAlberta during the fourth
quarter of 2011, reflecting the cumulative impact, from January 1, 2011,
of the decrease in the allowed ROE for 2011
-- Lower base component of customer rates at Maritime Electric associated
with the recovery of energy supply costs
-- Lower joint-use pole-related revenue at Newfoundland Power, due to new
support structure arrangements with Bell Aliant Inc. ("Bell Aliant") in
2011
Factors Contributing to Annual Revenue Variance
Favourable
-- Same factors as discussed above for the quarter
-- Higher electricity sales at the Canadian Regulated Electric Utilities
-- The recognition of $3.5 million of accrued revenue at FortisAlberta in
2011, related primarily to the cumulative 2010 and 2011 allowed return
and recovery of amortization on the additional $22 million in capital
expenditures associated with the Automated Metering Project, as approved
by the regulator to be included in rate base
Unfavourable
-- Same factors as discussed above for the quarter
-- Approximately $15 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 year over
year
-- Increased performance-based regulation ("PBR")-incentive adjustments to
be refunded to customers by FortisBC Electric
Factors Contributing to Quarterly Energy Supply Costs Variance
Favourable
-- Lower commodity cost of natural gas
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Lower purchased power costs at Maritime Electric and FortisBC Electric
Unfavourable
-- Increased fuel prices at Caribbean Utilities
-- Higher gas sales
Factors Contributing to Annual Energy Supply Costs Variance
Unfavourable
-- Same factors as discussed above for the quarter
-- Higher electricity sales at the Canadian Regulated Electric Utilities
Favourable
-- Same factors as discussed above for the quarter
-- Approximately $8 million associated with favourable foreign currency
translation
Factors Contributing to Quarterly and Annual
Operating Expenses Variances
Unfavourable
-- Higher operating expenses at the FortisBC Energy companies, mainly due
to increased wages and benefit costs, and higher asset removal costs,
partially offset by lower contractor and consulting expenses and labour
savings associated with changes in staffing levels
-- The regulator-approved reversal in the third quarter of 2010 at the
FortisBC Energy companies of $5 million ($4 million after tax) of
project overrun costs previously expensed in 2009 related to the
conversion of Whistler customer appliances from propane to natural gas
-- Higher operating expenses at Newfoundland Power, mainly due to the
regulator-approved change in the accounting treatment for other post-
employment benefit ("OPEB") costs, wage and general inflationary cost
increases, higher conservation costs related to customer rebate programs
and, in addition, increased employee-related expenses for the year.
-- Higher operating expenses at FortisBC Electric, largely due to increased
vegetation management costs, wage and general inflationary cost
increases and higher property taxes
Favourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Operating costs of approximately $2 million incurred during the third
quarter of 2010 at Newfoundland Power as a result of Hurricane Igor
-- Higher capitalized general overhead expenses, mainly at the FortisBC
Energy companies, FortisBC Electric and Newfoundland Power
-- Approximately $2 million for the year associated with favourable foreign
currency translation
Factors Contributing to Quarterly and Annual
Amortization Costs Variances
Unfavourable
-- Continued investment in energy infrastructure and income producing
properties
Favourable
-- Reduced amortization costs in 2011 at the FortisBC Energy companies,
mainly due to the retirement late in 2010 of certain general plant
assets and the amortization in 2011 of a regulatory deferral account
-- Regulator-approved increased amortization costs at Newfoundland Power in
2010, due to approximately $4 million of adjustments related to an
amortization study
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Approximately $1.5 million for the year associated with favourable
foreign currency translation
Factors Contributing to Annual
Other Income (Expenses) Variance
Favourable
-- The $17 million (US$17.5 million) fee paid to Fortis in July 2011,
following the termination of the Merger Agreement with Central Vermont
Public Service Corporation ("CVPS")
-- Lower corporate business development costs, due to $6 million incurred
in the first half of 2010
-- A net foreign exchange gain of $1 million associated with the previously
hedged investment in Belize Electricity
Factors Contributing to Quarterly and Annual
Finance Charges Variances
Unfavourable
-- Higher long-term debt levels in support of the utilities' capital
expenditure programs
Favourable
-- The refinancing of maturing corporate debt at lower rates
-- Higher capitalized allowance for funds used during construction
("AFUDC") for the year, mainly at FortisAlberta, partially offset by
lower capitalized AFUDC at FortisBC Electric
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
Factors Contributing to Quarterly and Annual
Corporate Taxes Variances
Unfavourable
-- Higher earnings before tax in taxable jurisdictions
-- Lower deductions for corporate income tax purposes compared to
accounting purposes
Favourable
-- Lower statutory income tax rates
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Higher earnings at the FortisBC Energy companies, driven by rate base
growth, lower-than-expected corporate income taxes and finance charges
in 2011, and higher gas transportation volumes to the forestry and
mining sectors, partially offset by both lower customer additions and
capitalized AFUDC
Unfavourable
-- Lower earnings at Newfoundland Power, mainly due to a lower allowed ROE
for 2011, lower earnings contribution associated with the new joint-use
pole support structure arrangements with Bell Aliant in 2011 and higher
operating expenses, partially offset by reduced energy supply costs in
the fourth quarter of 2011 and higher electricity sales
-- Lower earnings at the Other Canadian Regulated Electric Utilities,
mainly associated with decreased electricity sales and higher operating
expenses
-- Lower earnings at the Caribbean Regulated Electric Utilities, reflecting
lower earnings at Fortis Turks and Caicos associated with higher
amortization costs and operating expenses, partially offset by reduced
energy supply costs in 2011
-- Lower earnings at Fortis Properties, mostly due to higher corporate
income taxes
Factors Contributing to Annual Earnings Variance
Favourable
-- Higher earnings at the FortisBC Energy companies largely for the same
reasons as discussed above for the quarter, combined with lower-than-
expected amortization costs. Excluding the reversal in 2010 of certain
costs previously expensed in 2009, as discussed above in the operating
expenses variance, earnings at the FortisBC Energy companies were an
additional $4 million higher year over year.
-- Higher earnings at FortisAlberta, mainly due to rate base growth, higher
capitalized AFUDC, growth in the number of customers and higher energy
deliveries, return earned on additional investment in automated meters,
as approved by the regulator, and an approximate $1 million gain on the
sale of property, partially offset by the impact of a lower allowed ROE
for 2011
-- Higher earnings at FortisBC Electric, due to rate base growth and lower-
than-expected purchased power costs combined with higher electricity
sales, partially offset by lower capitalized AFUDC
-- Higher earnings at the Other Canadian Regulated Electric Utilities,
driven by a higher allowed ROE at Algoma Power
-- Lower net corporate expenses due to the $11 million after-tax
termination fee paid to Fortis in July 2011, combined with both lower
business development costs and finance charges
Unfavourable
-- Lower earnings at the Caribbean Regulated Electric Utilities for the
same reasons as discussed above for the quarter, combined with the
expropriation of Belize Electricity and the resulting discontinuance of
the consolidation method of accounting for the utility, effective June
20, 2011
-- Lower earnings at Fortis Properties for the same reason as discussed
above for the quarter, combined with lower contribution from the
Hospitality Division, partially offset by slightly increased
contribution from the Real Estate Division
-- Lower earnings at Non-Regulated Generation operations reflecting
decreased hydroelectric production in Belize, due to lower rainfall, and
overall lower interest income
-- Lower earnings at Newfoundland Power for the same reasons as discussed
above for the quarter
-- Approximately $1 million associated with unfavourable foreign currency
translation
SEGMENTED RESULTS OF OPERATIONS
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended December 31 Quarter Annual
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy Companies 51 45 6 139 130 9
----------------------------------------------------------------------------
Regulated Electric Utilities -
Canadian
FortisAlberta 17 17 - 75 68 7
FortisBC Electric 11 10 1 48 42 6
Newfoundland Power 8 9 (1) 34 35 (1)
Other Canadian Electric
Utilities 4 5 (1) 22 19 3
----------------------------------------------------------------------------
40 41 (1) 179 164 15
----------------------------------------------------------------------------
Regulated Electric Utilities -
Caribbean 3 4 (1) 20 23 (3)
Non-Regulated - Fortis
Generation 5 6 (1) 18 20 (2)
Non-Regulated - Fortis
Properties 5 7 (2) 23 26 (3)
Corporate and Other (18) (18) - (61) (78) 17
----------------------------------------------------------------------------
Net Earnings Attributable to
Common Equity Shareholders 86 85 1 318 285 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For a discussion of the material regulatory decisions and applications
pertaining to the Corporation's regulated utilities, refer to the "Regulatory
Highlights" section of this media release. 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 December 31 Quarter Annual
(TJ) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Core - Residential and
Commercial 42,202 37,035 5,167 128,161 113,635 14,526
Industrial 1,607 1,551 56 5,544 5,259 285
----------------------------------------------------------------------------
Total Sales Volumes 43,809 38,586 5,223 133,705 118,894 14,811
Transportation Volumes 18,741 18,405 336 67,813 60,363 7,450
Throughput under Fixed
Revenue
Contracts 203 3,407 (3,204) 1,237 13,765 (12,528)
----------------------------------------------------------------------------
Total Gas Volumes 62,753 60,398 2,355 202,755 193,022 9,733
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The FortisBC Energy companies are comprised of FEI, FEVI and FEWI.
Factors Contributing to Quarterly and Annual
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 and mining sectors
Unfavourable
-- Lower volumes under fixed revenue contracts, mainly due to higher
precipitation, which made it more cost efficient for a large customer to
not utilize its natural gas-powered generating facility for significant
periods during 2011
Net customer additions were 7,450 for 2011 compared to 9,393 for 2010. Net
customer additions decreased year over year due to lower building activity.
The FortisBC Energy companies earn approximately the same margin regardless of
whether a customer contracts for the purchase and delivery of natural gas or
only for the delivery of natural gas. As a result of the operation of
regulator-approved deferral mechanisms, changes in consumption levels and the
commodity cost of natural gas from those forecast to set residential and
commercial customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the FortisBC Energy
companies as a major portion of the gas distributed is used for space heating.
Most of the annual earnings of the FortisBC Energy companies are realized in the
first and fourth quarters.
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended December 31 Quarter Annual
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 477 479 (2) 1,568 1,546 22
Earnings 51 45 6 139 130 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Lower-than-expected customer additions
Favourable
-- An increase in the delivery component of customer rates, mainly due to
ongoing investment in energy infrastructure and forecasted higher
regulator-approved operating expenses recoverable from customers
-- Higher average gas consumption by residential and commercial customers
-- Higher gas transportation volumes to the forestry and mining sectors
Factors Contributing to Annual Revenue Variance
Favourable/Unfavourable
-- Same factors as discussed above for the quarter
Factors Contributing to Quarterly and Annual
Earnings Variances
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Lower-than-expected corporate income taxes and finance charges for the
quarter and the year, as well as lower-than-expected amortization costs
for the year
-- Higher gas transportation volumes to the forestry and mining sectors
Unfavourable
-- The regulator-approved reversal in third quarter of 2010 of $4 million
after tax of project overrun costs previously expensed in 2009, related
to the conversion of Whistler customer appliances from propane to
natural gas
-- Lower-than-expected customer additions in 2011
-- Lower capitalized AFUDC for the quarter, due to a lower asset base under
construction during 2011
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (GWh) 4,232 4,255 (23) 16,367 15,866 501
Revenue ($ millions) 102 99 3 409 385 24
Earnings ($ millions) 17 17 - 75 68 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Energy Deliveries Variance
Unfavourable
-- Lower average consumption by the gas sector, due to decreased activity
as a result of low gas market prices
-- Lower average consumption by the oilfield sector, and lower average
consumption by residential customers due to warmer-than-normal
temperatures in the fourth quarter of 2011
Favourable
-- Growth in the number of customers, with the total number of customers
increasing by approximately 8,000 period over period, driven by
favourable economic conditions
-- Higher average consumption by farm and irrigation customers, due to
differences in rainfall period over period
Factors Contributing to Annual Energy Deliveries Variance
Favourable
-- Same factors as discussed above for the quarter
-- Higher average consumption by residential customers, mainly due to
cooler-than-normal temperatures during the first quarter of 2011
Unfavourable
-- Lower average consumption by the gas sector, for the same reason 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 Annual
Revenue Variances
Favourable
-- The 4.7% increase in base customer electricity distribution rates,
effective January 1, 2011. The increase in base rates over 2010 rates
was primarily due to ongoing investment in energy infrastructure.
-- Growth in the number of customers
-- The recognition in 2011 of accrued revenue of $0.5 million for the
quarter and $3.5 million for the year, related primarily to the
cumulative allowed return and recovery of amortization on the additional
$22 million in capital expenditures approved by the regulator to be
included in rate base associated with the Automated Metering Project.
Approximately $1.5 million of the annual accrual related to 2010. For
further information, refer to the "Material Regulatory Decisions and
Applications - FortisAlberta" section of this media release.
Unfavourable
-- An approximate $2 million rate revenue reduction accrued during the
fourth quarter of 2011, reflecting the cumulative impact, from January
1, 2011, of the decrease in the allowed ROE to 8.75% for 2011 from 9.00%
for 2010
-- Differences in the amortization of regulatory deferrals to revenue
period over period, as approved by the regulator
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Higher capitalized AFUDC, due to a higher asset base under construction
during 2011
Unfavourable
-- The decrease in the allowed ROE for 2011, as discussed above
Factors Contributing to Annual Earnings Variance
Favourable
-- Same factors as discussed above for the quarter
-- Growth in the number of customers and energy deliveries
-- The allowed return and recovery of amortization of approximately $1.5
million recognized in 2011, relating to 2010, on the additional capital
expenditures associated with the Automated Metering Project, as
discussed above
-- An approximate $1 million gain on the sale of property
Unfavourable
-- Same factor as discussed above for the quarter
-- Lower return earned on the Alberta Electric System Operator ("AESO")
charges deferral, due to a decrease in the deferral balance
FORTISBC ELECTRIC (1)
---------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Electricity Sales (GWh) 843 847 (4) 3,143 3,046 97
Revenue ($ millions) 81 73 8 296 266 30
Earnings ($ millions) 11 10 1 48 42 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 Electricity Sales Variance
Unfavourable
-- Lower average consumption, due to warmer-than-normal temperatures
experienced during the fourth quarter of 2011 as compared to the same
quarter in 2010
Favourable
-- Growth in the number of customers
Factors Contributing to Annual Electricity Sales Variance
Favourable
-- Same factor as discussed above for the quarter
-- Lower average consumption during the first quarter of 2010, due to
warmer-than-normal temperatures experienced during that period,
resulting in higher electricity sales year over year
Factors Contributing to Quarterly and Annual
Revenue Variances
Favourable
-- A 6.6% increase in customer electricity rates, effective January 1,
2011, mainly reflecting ongoing investment in energy infrastructure
-- A 1.4% and 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 3.2% increase in electricity sales for the year, tempered by the
0.5% decrease in electricity sales for the quarter
-- Higher revenue contribution from non-regulated operating, maintenance
and management services
-- Higher wheeling revenue
-- Lower PBR-incentive adjustments to be refunded to customers for the
quarter
Unfavourable
-- Higher PBR-incentive adjustments to be refunded to customers for the
year
-- Lower surplus electricity sales for the year
Factors Contributing to Quarterly and Annual
Earnings Variances
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Lower-than-expected energy supply costs in 2011, primarily due to lower
average market-priced purchased power costs
-- Higher electricity sales for the year, as discussed above
-- Higher earnings contribution from non-regulated operating, maintenance
and management services for the year
Unfavourable
-- Lower capitalized AFUDC, due to a lower asset base under construction
during 2011
-- Higher effective corporate income taxes for the year, mainly due to
lower deductions for income tax purposes compared to accounting purposes
-- Higher-than-expected operating expenses for the fourth quarter of 2011
-- Lower electricity sales for the quarter, as discussed above
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 1,527 1,488 39 5,553 5,419 134
Revenue ($ millions) 156 152 4 573 555 18
Earnings ($ millions) 8 9 (1) 34 35 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Annual
Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption reflecting the higher concentration of
electric heating versus oil heating in new home construction combined
with strong economic growth
Factors Contributing to Quarterly and Annual
Revenue Variances
Favourable
-- The 2.6% and 2.5% increase in electricity sales for the quarter and
year, 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 from
9.00% for 2010
Unfavourable
-- Decreased amortization of regulatory liabilities and deferrals to
revenue, as approved by the regulator
-- Lower joint-use pole-related revenue, due to new support structure
arrangements with Bell Aliant, effective January 1, 2011. For further
information, refer to the "Material Regulatory Decisions and
Applications - Newfoundland Power" section of this media release.
Factors Contributing to Quarterly and Annual
Earnings Variances
Unfavourable
-- The decrease in the allowed ROE, as reflected in customer rates
-- Lower earnings contribution associated with the new joint-use pole
support structure arrangements with Bell Aliant in 2011
-- Higher effective corporate income taxes, primarily due to lower
deductions taken for income tax purposes compared to accounting
purposes, partially offset by a lower statutory income tax rate
-- Higher operating expenses related to wage and general inflationary cost
increases and higher conservation costs related to rebate programs
offered to customers. Higher operating expenses for the year were also
due to increased employee-related expenses, partially offset by lower
storm-related costs.
Favourable
-- Electricity sales growth
-- A reduction in energy supply costs in the fourth quarter of 2011
associated with the Company's hydroelectric generating facilities
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 568 578 (10) 2,366 2,328 38
Revenue ($ millions) 84 87 (3) 339 331 8
Earnings ($ millions) 4 5 (1) 22 19 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Quarterly Electricity Sales Variance
Unfavourable
-- Lower average consumption by residential customers in Ontario,
reflecting more moderate temperatures, which decreased home-heating load
-- Lower average consumption by industrial customers on Prince Edward
Island ("PEI") due to a reduction in farm-crop storage and warehousing
activities
Favourable
-- Growth in the number of residential customers
-- Higher average consumption by residential customers on PEI, reflecting
cooler temperatures which increased home-heating load
Factors Contributing to Annual Electricity Sales Variance
Favourable
-- Growth in the number of residential customers
-- Higher average consumption by residential customers in Ontario and on
PEI, reflecting cooler temperatures, which increased home-heating load
Unfavourable
-- Lower average consumption by industrial customers on PEI, for the same
reason as discussed above for the quarter
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- The 1.7% decrease in electricity sales
-- Lower basic component of customer rates at Maritime Electric associated
with the recovery of energy supply costs
-- A rate of return adjustment at Maritime Electric reducing revenue by
approximately $2 million in the fourth quarter of 2011, driven by
higher-than-expected electricity sales during 2011
-- Lower load demand revenue from commercial customers on PEI
Favourable
-- An average 3.8% increase in customer electricity rates at Algoma Power,
effective December 1, 2010, reflecting an increase in the allowed ROE to
9.85% for 2011 from 8.57% for 2010, and the use of a forward test year
for rate setting
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
Factors Contributing to Annual Revenue Variance
Favourable
-- Same factors as discussed above for the quarter
-- The 1.6% increase in electricity sales
Unfavourable
-- The rate of return adjustment at Maritime Electric during the fourth
quarter of 2011, as discussed above
-- Lower basic component of customer rates at Maritime Electric associated
with the recovery of energy supply costs
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Lower electricity sales at FortisOntario
-- The rate of return adjustment at Maritime Electric during the fourth
quarter of 2011, as discussed above
-- Higher operating expenses associated with vegetation management
activities, retirement and other employee-related costs
Favourable
-- A higher allowed ROE at Algoma Power and the use of a forward test year
for rate setting, as reflected in customer rates for 2011
-- Rate base growth, due to continued investment in energy infrastructure
-- Lower effective corporate income taxes, primarily due to higher
deductions taken for income tax purposes compared to accounting purposes
Factors Contributing to Annual Earnings Variance
Favourable
-- Same factors as discussed above for the quarter
-- Electricity sales growth
Unfavourable
-- The rate of return adjustment at Maritime Electric during the fourth
quarter of 2011, as discussed above
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate
(2) 1.02 1.01 0.01 0.99 1.03 (0.04)
Electricity Sales (GWh) 174 270 (96) 918 1,150 (232)
Revenue ($ millions) 70 84 (14) 305 333 (28)
Earnings ($ millions) 3 4 (1) 20 23 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which
Fortis holds an approximate 60% 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
expropriated the Corporation's investment in Belize Electricity. As a
result, Fortis discontinued the consolidation method of accounting for
Belize Electricity, effective June 20, 2011. For further information,
refer to the "Corporate Overview" section of this media release.
(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 Annual
Electricity Sales Variances
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011. For further information, refer to the "Corporate
Overview" section of this media release.
-- Reduced energy consumption due to challenging economic conditions in the
region, the high cost of fuel, and the early and extended closure of
certain hotel and other commercial customers in the Turks and Caicos
Islands resulting from a hurricane in August 2011
-- The number of work permit holders in the region has declined
significantly, causing some rental properties with active electricity
connections to be vacant.
Favourable
-- Growth in the number of customers in Grand Cayman and the Turks and
Caicos Islands
-- Excluding Belize Electricity, electricity sales growth was 3.7% for the
quarter. There was no growth in electricity sales year over year
-- Electricity sales for the fourth quarter of 2011 were impacted by warmer
weather conditions in the region that favourably impacted customer air
conditioning load
Factors Contributing to Quarterly and Annual
Revenue Variances
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Approximately $13 million of unfavourable foreign exchange for the year
associated with the translation of foreign currency-denominated revenue,
due to the weakening of the US dollar relative to the Canadian dollar
year over year
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the price of fuel
-- Higher electricity sales for the quarter, excluding Belize Electricity
-- Approximately $1 million of favourable foreign exchange for the quarter
associated with the translation of foreign currency-denominated revenue,
due to the strengthening of the US dollar relative to the Canadian
dollar quarter over quarter
Factors Contributing to Quarterly and Annual
Earnings Variances
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011. There was no earnings contribution from Belize
Electricity during 2011, while the Company contributed $1.5 million in
earnings in 2010, with a loss of $0.5 million incurred in the fourth
quarter of 2010.
-- Higher amortization, excluding the impact of foreign exchange, largely
at Fortis Turks and Caicos, due to investment in utility capital assets,
including the commencement of amortization in 2011 of a new operations
centre and generating unit
-- Higher operating expenses, excluding the impact of foreign exchange, at
Fortis Turks and Caicos, largely due to consulting fees associated with
ongoing regulatory matters and inflationary cost increases
Favourable
-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more
fuel-efficient production realized with the commissioning of new
generation units at the utility
-- Higher electricity sales for the quarter, excluding Belize Electricity
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December 31 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 112 137 (25) 389 427 (38)
Revenue ($ millions) 9 9 - 34 36 (2)
Earnings ($ millions) 5 6 (1) 18 20 (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State, with a combined generating capacity of 139 MW, mainly
hydroelectric. Results reflect contribution from the Vaca
hydroelectric generating facility in Belize from late March 2010 when
the facility was commissioned.
Factors Contributing to Quarterly and Annual
Energy Sales Variances
Unfavourable
-- Decreased production in Belize for the year, due to lower rainfall in
the first three quarters of 2011 associated with a longer dry season
-- Decreased production in Upper New York State, due to a generating plant
being out of service since May 2011
Favourable
-- Increased production in Belize for the quarter, due to higher rainfall
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Lower average energy sales rate per megawatt hour ("MWh") in Upper New
York State. The average rate per MWh for the fourth quarter of 2011 was
US$35.79 compared to US$43.64 for the same quarter in 2010.
Favourable
-- Increased production in Belize
Factors Contributing to Annual Revenue Variance
Unfavourable
-- Decreased production in Belize
Favourable
-- Higher annual average energy sales rate per MWh in Ontario. The annual
average rate per MWh was $72.96 in 2011 compared to $53.17 in 2010.
Effective May 1, 2010, energy produced in Ontario is being sold under a
fixed-price contract with price indexing. Previously, energy was sold at
market rates.
Factors Contributing to Quarterly Earnings Variances
Unfavourable
-- Lower average energy sales rate per MWh in Upper New York State
-- Lower interest income at Ontario operations associated with lower inter-
company lending to regulated operations in Ontario
-- Higher business development costs at Ontario operations
Favourable
-- Increased production in Belize
Factors Contributing to Annual Earnings Variances
Unfavourable
-- Decreased production in Belize
-- Lower interest income at Ontario operations, for the same reason as
discussed above for the quarter
Favourable
-- Higher annual average energy sales rate per MWh in Ontario
-- Lower finance charges and higher interest income associated with
operations in Belize
In May 2011 the generator at Moose River's hydroelectric generating facility in
Upper New York State sustained damage. Equipment and business interruption
insurance claims are ongoing. Revenue for 2011 reflects the accrual of the 2011
earnings impact of the shut down of the facility that is recoverable from the
insurance claim. The generator is under repair and the facility is expected to
be operational in late March 2012.
NON-REGULATED - FORTIS PROPERTIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended December 31 Quarter Annual
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality Revenue 41 40 1 164 160 4
Real Estate Revenue 17 17 - 67 66 1
----------------------------------------------------------------------------
Total Revenue 58 57 1 231 226 5
----------------------------------------------------------------------------
Earnings 5 7 (2) 23 26 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 22 hotels, collectively
representing 4,300 rooms in eight Canadian provinces, and
approximately 2.7 million square feet of commercial office and retail
space primarily in Atlantic Canada.
Factors Contributing to Quarterly Revenue Variance
Favourable
-- Revenue contribution from the Hilton Suites Winnipeg Airport hotel,
which was acquired in October 2011
-- A 2.3% increase in revenue per available room ("RevPar"), excluding the
impact of the Hilton Suites Winnipeg Airport hotel, at the Hospitality
Division to $72.39 for the fourth quarter of 2011 from $70.76 for the
same quarter of 2010. RevPar increased due to an overall 2.6% increase
in the average daily room rate, partially offset by an overall 0.3%
decrease in hotel occupancy. The average daily room rate increased in
all regions. Occupancy increases were achieved in Atlantic Canada and
central Canada but were more than offset by occupancy decreases
experienced in western Canada. Including the Hilton Suites Winnipeg
Airport hotel, RevPar was $73.66 for the fourth quarter of 2011.
-- Rental rate increases at the Real Estate Division
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division to 93.2% as
at December 31, 2011 from 94.5% as at December 31, 2010
Factors Contributing to Annual Revenue Variance
Favourable
-- Revenue contribution from the Hilton Suites Winnipeg Airport hotel, as
discussed above for the quarter
-- A 2.1% increase in RevPar, excluding the impact of the Hilton Suites
Winnipeg Airport hotel, at the Hospitality Division to $78.48 for 2011
from $76.83 for 2010. RevPar increased due to an overall 2.7% increase
in the average daily room rate, partially offset by an overall 0.6%
decrease in hotel occupancy. The average daily room rate increased in
all regions. Occupancy increases were achieved in Atlantic Canada and
central Canada but were more than offset by occupancy decreases
experienced in western Canada. Including the Hilton Suites Winnipeg
Airport hotel, RevPar was $78.76 for 2011.
-- Rental rate increases at the Real Estate Division
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division, as
discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher corporate income taxes. Lower statutory income tax rates and
their effect of reducing future income tax liability balances in the
fourth quarter of 2010 favourably impacted corporate income taxes in
2010.
Favourable
-- Higher contribution from the Hospitality Division, driven by the Hilton
Suites Winnipeg Airport hotel, which was acquired in October 2011
Factors Contributing to Annual Earnings Variance
Unfavourable
-- Same factor as discussed above for the quarter
-- Lower contribution from the Hospitality Division, reflecting lower
performance at operations in western Canada, due to decreased occupancy
rates, and at operations in central Canada, partially offset by improved
performance at operations in Newfoundland, Atlantic Canada, reflecting
strong local economic conditions
-- Higher corporate administrative expenses
Favourable
-- Higher contribution from the Real Estate Division, mainly due to the
$0.5 million gain on the sale of the Viking Mall in 2011
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended December 31 Quarter Annual
($ millions) 2011 2010 Variance 2011 2010 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 7 7 - 29 29 -
Operating Expenses 3 4 (1) 10 10 -
Amortization 2 2 - 7 7 -
Other Income (Expenses), Net 1 - 1 21 (5) 26
Finance Charges (2) 17 16 1 71 73 (2)
Corporate Tax Recovery (3) (4) 1 (6) (16) 10
------------------------------------------
(11) (11) - (32) (50) 18
Preference Share Dividends 7 7 - 29 28 1
----------------------------------------------------------------------------
Net Corporate and Other Expenses (18) (18) - (61) (78) 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Annual
Net Corporate and Other Expenses Variance
Favourable
-- Higher other income, net of expenses, due to: (i) a $17 million (US$17.5
million) ($11 million after tax) fee paid to Fortis in July 2011,
following the termination of a Merger Agreement between Fortis and CVPS;
and (ii) a $4.5 million foreign exchange gain associated with the
translation of the US dollar-denominated long-term other asset
representing the book value of the Corporation's former investment in
Belize Electricity. The foreign exchange gain was partially offset by a
$3.5 million ($3 million after-tax) foreign exchange loss associated
with the translation of previously hedged US dollar-denominated debt.
The favourable net impact to 2011 earnings of the above foreign exchange
impacts was approximately $1.5 million. Business development costs of
approximately $6 million ($4 million after tax) incurred in the first
half of 2010 also had a favourable impact on other income, net of
expenses, year over year.
-- Lower finance charges due to the refinancing of maturing corporate debt
at lower rates, the repayment of credit facility borrowings during the
third quarter of 2011 with a portion of the proceeds from the common
share offering in June and July 2011, and the favourable foreign
exchange impact associated with the translation of US dollar-denominated
interest expense.
Unfavourable
-- Finance charges were reduced in the fourth quarter of 2010, related to
the finalization of capitalized interest on a construction project.
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series H in January 2010
On July 11, 2011, the Board of Directors of CVPS determined that the acquisition
proposal from Gaz Metro Limited Partnership was a "Superior Proposal", as that
term was defined in the Merger Agreement between Fortis and CVPS announced on
May 30, 2011, and CVPS elected to terminate the Merger Agreement in accordance
with its terms. Prior to such termination taking effect, the Merger Agreement
provided Fortis the right to require CVPS to negotiate with Fortis for at least
five business days with respect to any changes to the terms of the Merger
Agreement proposed by Fortis. Fortis agreed to waive such right in exchange for
the prompt payment by CVPS to Fortis of the US$17.5 million termination fee plus
US$2.0 million for the reimbursement of expenses as set forth in the Merger
Agreement, thereby resulting in the termination of the Merger Agreement. Fortis
received the $18.8 million (US$19.5 million) payment on July 12, 2011.
REGULATORY HIGHLIGHTS
The nature of material regulatory decisions and applications associated with
each of the Corporation's regulated gas and electric utilities for 2011 are
summarized as follows:
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
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Regulated Utility Summary Description
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FEI/FEVI/FEWI - FEI and FEWI review with the British Columbia Utilities
Commission ("BCUC") natural gas and propane commodity
prices every three months and midstream costs annually, in
order to ensure the flow-through rates charged to
customers are sufficient to cover the cost of purchasing
natural gas and propane and contracting for midstream
resources, such as third-party pipeline and/or storage
capacity. The commodity cost of natural gas and propane
and midstream costs are flowed through to customers
without markup. The bundled rate charged to FEVI customers
includes a component to recover approved gas costs and is
set annually. In order to ensure that the balance in the
Commodity Cost Reconciliation Account is recovered on a
timely basis, FEI and FEWI prepare and file quarterly
calculations with the BCUC to determine whether customer
rate adjustments are needed to reflect prevailing market
prices for natural gas. These rate adjustments ignore the
temporal effect of derivative valuation adjustments on the
balance sheet and, instead, reflect the forward forecast
of gas costs over the recovery period.
- Effective January 1, 2011, rates for residential
customers in the Lower Mainland, Fraser Valley and
Interior, North and Kootenay service areas decreased by
approximately 6%, as approved by the BCUC, to reflect net
changes in delivery, commodity and midstream costs.
Effective January 1, 2011, FEWI's interim residential
customer rates decreased by approximately 5% and FEVI's
rates remained unchanged.
- Natural gas commodity rates remained unchanged for April
1, 2011 and July 1, 2011, following the BCUC's quarterly
reviews of commodity costs.
- Effective October 1, 2011, rates for residential
customers in the Lower Mainland, Fraser Valley and
Interior, North and Kootenay service areas decreased by
approximately 5% to reflect changes in commodity costs,
following the BCUC's quarterly review of such costs. FEWI
and FEVI's rates remained unchanged.
- Effective January 1, 2012, rates for residential
customers in the Lower Mainland, Fraser Valley and
Interior, North and Kootenay service areas increased by
approximately 3% and rates for FEWI's residential
customers increased by approximately 6%, reflecting
changes in delivery and midstream costs with the rates
being set on an interim basis, pending a final decision on
the gas utilities' 2012-2013 Revenue Requirements
Applications. Interim approval has also been received from
the BCUC to hold FEVI customer rates at 2011 levels,
effective January 1, 2012. Natural gas commodity rates
remained unchanged, effective January 1, 2012.
- In December 2010 FEI filed an application with the BCUC
to provide fueling services through FEI-owned and operated
compressed natural gas and liquefied natural gas ("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.
FEI refiled an amended application for a general tariff
and is awaiting a final decision from the BCUC.
- In May 2011, in response to a complaint, the BCUC
initiated a public process to develop guidelines under
which FEI should be able to provide "alternative energy
services" as regulated utility services. The "alternative
energy services" offered by FEI include providing
refueling services for natural gas vehicles ("NGVs"),
owning and operating district energy systems and various
forms of geo-exchange systems, and owning facilities that
upgrade raw biogas into biomethane for the purpose of
selling it to customers.
- 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 US
generally accepted accounting principles ("US GAAP")
effective January 1, 2012 for regulatory reporting
purposes.
- In July 2011 FEVI received a BCUC decision approving the
option for two First Nations bands to invest up to 15% in
the equity component of the capital structure of the new
LNG storage facility on Vancouver Island. In late 2011
each band exercised its option and each invested
approximately $6 million in equity in the LNG facility on
January 1, 2012.
- In August 2011 FEI and FEVI received a decision from the
BCUC on the use of Energy Efficiency and Conservation
("EEC") funds as incentives for NGVs. The utilities had
made these funds available to assist large customers in
purchasing NGVs in lieu of vehicles fueled by diesel. The
decision determined that it was not appropriate to use EEC
funds for this purpose and the BCUC has requested that the
companies provide further submissions to determine the
prudency of the EEC incentives at a future time.
- In January 2011 FEI and FEVI filed a report of a review
of their Price Risk Management Plan ("PRMP") objectives
with the BCUC related to their gas commodity hedging plan
and FEI also submitted a revised 2011-2014 PRMP. In July
2011 the BCUC issued its decision on the report and
determined that commodity hedging in the current
environment was not a cost-effective means of meeting the
objectives of price competitiveness and rate stability.
The BCUC concurrently denied FEI's 2011-2014 PRMP with the
exception of certain elements to address regional price
discrepancies. As a result, FEVI and FEI have suspended
commodity-hedging activities with the exception of limited
swaps as permitted by the BCUC. The existing hedging
contracts are expected to continue in effect through to
their maturity and the gas utilities' ability to fully
recover the commodity cost of gas in customer rates
remains unchanged.
- In September 2011 the FortisBC Energy companies filed an
update to their 2012-2013 Revenue Requirements
Applications. FEI has requested an increase in rates of
3.0%, effective January 1, 2012, and 3.1%, effective
January 1, 2013, reflecting an increase in the delivery
component of customer rates. FEI's application assumes
forecast average rate base of approximately $2,760 million
for 2012 and $2,820 million for 2013. FEVI has requested
that rates remain unchanged for the two-year period
commencing January 1, 2012. FEVI's application assumes
forecast average rate base of $788 million for 2012 and
$816 million for 2013. FEWI has requested an increase in
rates of approximately 6.5%, effective January 1, 2012,
and approximately 4.3%, effective January 1, 2013,
reflecting an increase in the delivery component of
customer rates. FEWI's application assumes forecast
average rate base of $42 million for 2012 and $41 million
for 2013. The requested rates reflect allowed ROEs and
capital structure unchanged from 2011. The requested rate
increases are driven by ongoing investment in energy
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 system, and increasing
compliance with codes and regulations. A decision on the
rate applications is expected in the first half of 2012.
- In October 2011 FEI filed an application for approval of
expenditures of approximately $5 million on facilities
required to provide thermal energy services to 19
buildings in the Delta School District located in the
Greater Vancouver area. When complete, FEI will own,
operate and maintain the new thermal plants and charge the
Delta School District a single rate for thermal energy
consumed. In November 2011 FEI refiled the application
with amended third-party contracts related to the thermal
energy services to allow more time for a public review
process. A decision on the application is expected by the
end of the first quarter of 2012.
- In November 2011 FEI, FEVI and FEWI filed an application
with the BCUC for the amalgamation of the three companies
into one legal entity, and for the implementation of
common rates and services for the utilities' customers
across British Columbia, effective January 1, 2013. The
amalgamation requires approval by the BCUC and consent of
the Government of British Columbia. In late 2011 the
utilities temporarily suspended their application while
they are providing additional information to the BCUC, as
requested.
- In November 2011 the BCUC gave preliminary notification
to public utilities subject to its regulation, including
the FortisBC Energy companies and FortisBC Electric, of
its intention to initiate a Generic Cost of Capital
proceeding early in 2012. During the proceeding, the BCUC
intends to review the following items: (i) setting the
appropriate cost of capital for a benchmark low-risk
utility; (ii) establishing an ROE automatic adjustment
mechanism; and (iii) establishing a deemed capital
structure and deemed cost of capital methodology,
particularly for those utilities in British Columbia
without third-party debt. FortisBC will be involved in
this regulatory process in 2012. The cost of capital
review may result in a change in the utilities' capital
structures and allowed ROEs.
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FortisBC Electric - In December 2010 the BCUC approved a Negotiated
Settlement Agreement ("NSA") pertaining to FortisBC
Electric's 2011 Revenue Requirements Application and
Capital Expenditure Plan. 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 energy
infrastructure, including increased amortization and
financing costs.
- Effective June 1, 2011, the BCUC approved an increase of
1.4% in FortisBC Electric customer electricity rates
arising from an increase in purchased power costs due to
an increase in BC Hydro rates.
- In June 2011 FortisBC Electric filed its 2012-2013
Revenue Requirements Application, which included its 2012-
2013 Capital Expenditure Plan, and its Integrated System
Plan ("ISP"). The ISP includes the Company's Resource
Plan, Long-Term Capital Plan and Long-Term Demand Side
Management Plan. FortisBC Electric requested an interim 4%
increase in customer electricity rates effective January
1, 2012 and a 6.9% increase effective January 1, 2013. The
rate increases are due to ongoing investment in energy
infrastructure, including increased costs of financing the
investment, as well as increased purchased power costs.
The requested rates reflect an allowed ROE and capital
structure unchanged from 2011. In addition to a
continuation of deferral accounts and flow-through
treatments that existed under the PBR agreement, which
expired at the end of 2011, the 2012-2013 Revenue
Requirements Application proposes deferral accounts and
flow-through treatment for variances from the forecast
used to set customer rates for electricity revenue,
purchased power costs and certain other costs.
- In November 2011 FortisBC Electric filed an updated
2012-2013 Revenue Requirements Application to include
updated financial estimates and forecasts, resulting in a
revised requested increase in rates of 1.5%, effective
January 1, 2012, and 6.5%, effective January 1, 2013. The
revised application assumes forecast average rate base of
approximately $1,146 million for 2012 and $1,215 million
for 2013. An oral hearing process is expected to occur in
March 2012 with a decision expected during 2012.
- An interim, refundable customer rate increase of 1.5%,
effective January 1, 2012, was approved by the BCUC,
pending a final decision on the Company's 2012-2013
Revenue Requirements Application.
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FortisAlberta - In December 2010 the Alberta Utilities Commission
("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.
- In June 2011 the AUC issued its decision regarding the
prudency of additional capital expenditures above $104
million related to the Company's Automated Metering
Project. In its decision, the AUC concluded that the full
amount of the forecasted total project cost of $126
million could be included in rate base and collected in
customer rates. The impact of the decision was the
recognition of $3.5 million in accrued revenue in 2011 and
an associated regulatory asset as at December 31, 2011.
- In October 2010 the Central Alberta Rural
Electrification Association ("CAREA") filed an application
with the AUC requesting that, effective January 1, 2012,
CAREA be entitled to service any new customers wishing to
obtain electricity for use on property overlapping CAREA's
service area and that FortisAlberta be restricted to
providing service in the CAREA service area only to those
customers in that service area who are not being provided
service by CAREA. FortisAlberta has intervened in the
proceedings to oppose CAREA's request. A decision on this
matter is expected in 2012.
- In 2010 the AUC initiated a process to reform utility
rate regulation for distribution utilities in Alberta. The
AUC intends to introduce PBR-based distribution service
rates beginning in 2013 for a five-year term, with 2012 to
be used as the base year. In July 2011 FortisAlberta,
along with other distribution utilities operating under
the AUC's jurisdiction, submitted PBR proposals to the
AUC. The Company's submission outlines its views as to how
PBR should be implemented at FortisAlberta. A hearing on
the matter is expected to commence in April 2012 with a
decision expected in 2012.
- In March 2011 FortisAlberta filed its 2012 and 2013 DTA.
The AUC allowed FortisAlberta, at the Company's request,
to settle the DTA through negotiation, but stipulated that
the negotiation apply only to 2012 rates in light of the
AUC's target of commencing PBR-based rate setting in 2013.
In November 2011 FortisAlberta filed an NSA pertaining to
2012 customer distribution rates. The NSA proposes an
average rate increase of approximately 5% effective
January 1, 2012. FortisAlberta's average rate base is
currently forecast at $2.0 billion for 2012 and $2.3
billion for 2013. The requested rate increase is driven
primarily by ongoing investment in energy infrastructure,
including increased amortization and financing costs. In
December 2011 the AUC approved an interim average rate
increase of approximately 5%, effective January 1, 2012,
reflecting the parameters of the NSA. The Company has also
requested that volume variances be included in
FortisAlberta's AESO charges deferral account for 2012,
consistent with the deferral structure that was in place
in 2011. A decision on the NSA is expected in the first
half of 2012.
- In December 2011 the AUC issued its decision on its 2011
Generic Cost of Capital Proceeding, establishing the
allowed ROE at 8.75% for 2011 and 2012, and, on an interim
basis, at 8.75% for 2013. The equity component of
FortisAlberta's capital structure remains at 41% and will
continue at that level until any future order of the AUC
that may change it. The AUC concluded that it would not
return to a formula-based ROE automatic adjustment
mechanism at this time and that it would initiate a
proceeding in due course to establish a final allowed ROE
for 2013 and to revisit the matter of a return to a
formula-based approach in future periods. FortisAlberta
and other distribution utilities in Alberta filed motions
for leave to appeal with the Alberta Court of Appeal with
respect to the cost of capital decision challenging
certain pronouncements made by the AUC as being
incorrectly made regarding cost responsibility for
stranded assets. In February 2012 FortisAlberta and other
utilities filed requests with the AUC for the AUC to
review and vary its pronouncements.
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Newfoundland - In December 2010 the Newfoundland and Labrador Board of
Power Commissioners of Public Utilities ("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 applicable generally accepted accounting
principles and OPEB expense approved by the PUB for rate-
setting purposes.
- In December 2010 Newfoundland Power received approval
from the PUB for an overall average 0.8% increase in
customer electricity rates, effective January 1, 2011,
mainly resulting from the PUB's approval for the Company
to change its accounting for OPEB costs, as described
above, partially offset by the impact of the decrease in
the allowed ROE for 2011.
- On January 1, 2011, new support structure arrangements
with Bell Aliant went into effect, including Bell Aliant
repurchasing 40% of all joint-use poles and related
infrastructure from Newfoundland Power, representing
approximately 5% of Newfoundland Power's rate base. In
2001 Newfoundland Power purchased Bell Aliant's (formerly
Aliant Telecom Inc.) joint-use poles and related
infrastructure under a 10-year Joint-Use Facilities
Partnership Agreement ("JUFPA"), which expired on December
31, 2010. Bell Aliant had rented space on these poles from
Newfoundland Power since 2001 with the right to repurchase
40% of all joint-use poles at the end of the term of the
JUFPA. Bell Aliant exercised the option to buy back these
poles from Newfoundland Power in 2010. The new support
structure arrangements were subject to certain conditions,
including PUB approval of the sale of the joint-use poles.
The PUB issued an order approving the sale of the joint-
use poles in September 2011. Effective January 1, 2011,
Newfoundland Power no longer received pole rental revenue
from Bell Aliant. Newfoundland Power was responsible for
the construction and maintenance of Bell Aliant's support
structure requirements in 2011. The new support structure
arrangements had no material impact on Newfoundland
Power's ability to earn a reasonable return on its rate
base in 2011. Proceeds of approximately $46 million from
the sale of 40% of the joint-use poles were received by
Newfoundland Power from Bell Aliant in October 2011. The
sale proceeds were used to pay down credit facility
borrowings and pay a special dividend of approximately $30
million to Fortis in order to maintain Newfoundland
Power's capital structure at 45% common equity. In January
2012 the transaction with Bell Aliant closed and a
purchase price adjustment of approximately $1 million was
paid to Bell Aliant by Newfoundland Power. The purchase
price adjustment was based on the results of a pole survey
completed in the fourth quarter of 2011.
- In October 2011 the PUB approved Newfoundland Power's
application requesting the deferral of expected increased
costs of $2.4 million in 2012, due to expiring regulatory
amortizations.
- In December 2011 the PUB approved Newfoundland Power's
application requesting the adoption of US GAAP, effective
January 1, 2012, for regulatory reporting purposes.
- In December 2011 the PUB approved, as filed,
Newfoundland Power's 2012 Capital Expenditure Plan
totalling approximately $77 million.
- In November 2011 Newfoundland Power's allowed ROE for
2012 was calculated at 7.85% under the ROE automatic
adjustment formula, a decrease from 8.38% for 2011. In
December 2011 the PUB approved an application filed by
Newfoundland Power requesting the suspension of the
operation of the ROE automatic adjustment formula for 2012
and to review cost of capital for 2012. As a result,
current customer rates and the allowed ROE of 8.38% will
continue in effect for 2012 on an interim basis. A full
cost of capital review is expected to be held by the PUB
in 2012.
- Newfoundland Power's average rate base for 2012 is
forecasted at $879 million.
- The Company is currently assessing the requirement for
it to file a general rate application with the PUB to
recover increased costs in 2013.
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Maritime Electric - In November 2010 Maritime Electric signed the PEI Energy
Accord (the "Accord") with the Government of PEI. The
Accord covers the period from March 1, 2011 through
February 29, 2016. Under the terms of the Accord, the
Government of PEI is assuming responsibility for the cost
of incremental replacement energy and the monthly
operating and maintenance costs related to the New
Brunswick Power ("NB Power") Point Lepreau Nuclear
Generating Station ("Point Lepreau"), effective March 1,
2011 until Point Lepreau is fully refurbished, which is
expected by fall 2012. The Government of PEI is financing
these costs, which will be recovered from customers. In
the event that Point Lepreau does not return to service by
fall 2012, the Government of PEI reserves the right to
cease the monthly payments. As permitted by the Island
Regulatory and Appeals Commission ("IRAC"), incremental
replacement energy costs incurred during the refurbishment
of Point Lepreau up to the end of February 2011 were
deferred by Maritime Electric and totalled approximately
$47 million. The deferred costs are included in rate base.
- The nature and timing of the recovery of the deferred
costs related to Point Lepreau is subject to further
review by the PEI Energy Commission (the "Commission"),
which was recently established by the Government of PEI.
Having authority under the Public Inquiries Act, the co-
chaired five-member Commission's goal is to examine and
provide advice on ways in which PEI's cost of electricity
can be structurally reduced and/or stabilized over the
longer term. In carrying out this goal, the Commission
will, amongst other things, examine and provide
recommendations on long-term ownership and management of
electricity on PEI and provide advice and recommendations
as to the future role of the PEI Energy Corporation, IRAC
(as it relates to electricity) and the Office of Energy
Efficiency.
- The Accord also provides for the financing by the
Government of PEI of costs associated with Maritime
Electric's termination of the Dalhousie Unit Participation
Agreement. The costs will be collected from customers over
a period to be established by the Government of PEI. As a
result of the Accord, including the favourable impact on
purchased power costs of the new five-year power purchase
agreement between Maritime Electric and NB Power, customer
electricity rates decreased overall by approximately 14%,
effective March 1, 2011, reflecting a decrease in the
Energy Cost Adjustment Mechanism and base component of
rates. A two-year customer rate freeze commenced after the
March 1, 2011 rate adjustment. The allowed ROE for 2011
and 2012 is 9.75%, as set under the terms of the Accord.
- Maritime Electric intends to file an application with
IRAC in fall 2012 for 2013 customer rates and allowed ROE.
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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 Ontario Energy
Board ("OEB"). In March 2011 the OEB published the
applicable inflationary and efficiency targets, which
resulted in minimal changes in base customer electricity
distribution rates at FortisOntario's operations in Fort
Erie, Gananoque and Port Colborne.
- In November 2010 the OEB approved an NSA pertaining to
Algoma Power's electricity distribution rate application
for customer rates, effective December 1, 2010 through
December 31, 2011, using a 2011 forward test year. The
rates reflected an approved allowed ROE of 9.85% on a
deemed equity component of capital structure of 40%. The
overall impact of the OEB rate decision on an average
customer's electricity bill, including rate riders and
other charges, was an overall increase of 3.8%.
- The present form of Third-Generation IRM will not
accommodate Algoma Power's customer rate structure and the
Rural and Remote Rate Protection ("RRRP") Program. Algoma
Power consulted with the intervener community to develop a
form of incentive rate-making that may be used between
rebasing periods. Due to regulations in Ontario associated
with the RRRP Program, customer electricity distribution
rates at Algoma Power are tied to the average changes in
rates of other electric utilities in Ontario. The balance
of Algoma Power's revenue requirement is recovered from
the RRRP Program. In September 2011 Algoma Power filed its
first Third-Generation IRM application for customer
electricity distribution rates, effective January 1, 2012.
The Third-Generation IRM maintains the allowed ROE at
9.85%. Algoma Power has proposed that both electricity
rates and funding under the RRRP Program be indexed
through a price-cap formula. In December 2011 the OEB
approved current customer rates as interim rates for 2012
for Algoma Power, pending a final decision on Algoma
Power's rate application. The outcome of Algoma Power's
rate application will likely determine whether the Company
will remain under incentive regulation for the full IRM
cycle.
- In April 2011 FortisOntario provided the City of Port
Colborne and Port Colborne Hydro Inc. ("Port Colborne
Hydro") with an irrevocable written notice of
FortisOntario's election to exercise the purchase option,
under the current operating lease agreement, at the
purchase option price of approximately $7 million on April
15, 2012. The purchase constitutes the sale of the
remaining assets of Port Colborne Hydro to FortisOntario.
The purchase is subject to OEB approval.
- In November 2011 the OEB published the applicable
inflationary factor of 1.7% for Third-Generation IRM rate
applications having a January 1, 2012 effective date.
- In November 2011 FortisOntario filed a Third-Generation
IRM application for rates effective May 1, 2012 for its
operations in Port Colborne and a similar, but harmonized,
rate application for its operations in Fort Erie and
Gananoque, effective May 1, 2012. The Third-Generation IRM
maintains the allowed ROE at 8.01% for 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.
- In November 2011 the OEB published the allowed ROE of
9.42% for 2012, as calculated under the ROE automatic
adjustment mechanism. This allowed ROE is not applicable
to regulated electric utilities in Ontario until they are
scheduled to file full COS rate applications. As a result,
this allowed ROE will not be applicable to FortisOntario's
utilities in 2012.
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Caribbean - In March 2011 Caribbean Utilities confirmed to the
Utilities Electricity Regulatory Authority ("ERA") that the Rate-Cap
Adjustment Mechanism, 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 a Fuel Price Volatility
Management Program for the utility. The objective of the
program is to reduce the impact of volatility in the fuel
cost charge paid by Caribbean Utilities' customers for the
fuel that it must purchase in order to provide electric
service. The program utilizes call options creating a
ceiling price for fuel costs at predetermined contract
premiums. The program currently covers 40% of expected
fuel consumption.
- In July 2011 the ERA approved Caribbean Utilities'
request to use US GAAP for regulatory reporting purposes,
effective January 1, 2012.
- In March 2011 the ERA approved $134 million of proposed
non-generation installation expenditures in Caribbean
Utilities' 2011-2015 Capital Investment Plan ("CIP"). The
remaining $85 million of the CIP related to new generation
installation, which would be subject to a competitive
solicitation process.
- In November 2011 CUC issued a Certificate of Need to the
ERA for 18 MW of new generating capacity to be installed
in 2014 and for an additional 18 MW of generating capacity
to be installed in either 2015 or 2016, contingent on
growth over the next two years. The primary driver for the
new generating capacity in 2014 is the upcoming scheduled
retirements of several of Caribbean Utilities' generating
units, which are reaching the end of their useful lives.
As a result of the Company expressing its need for
replacement capacity, the ERA will be conducting a
competitive solicitation process in 2012 in accordance
with Caribbean Utilities' licenses, which will allow all
interested and qualified parties, including Caribbean
Utilities, to submit bids to fill the Company's firm
capacity requirement.
- In December 2011 Caribbean Utilities filed its 2012-2016
CIP totaling approximately US$192 million, including
generation capital expenditures. The 2012-2016 CIP has
been prepared in line with the Certificate of Need that
was filed with the ERA in November 2011, as discussed
above. A decision on the CIP is expected during the first
quarter of 2012.
- In December 2011 Caribbean Utilities conducted and
completed a competitive bidding process to fill 13 MW of
nonfirm renewable energy capacity. There are currently no
viable renewable energy sources on Grand Cayman that meet
Caribbean Utilities' reliability requirements for firm
capacity; however, Caribbean Utilities expects that there
are third parties that can build and maintain renewable
energy plants on Grand Cayman and sell energy to Caribbean
Utilities' at a competitive price to diesel. Any resulting
power purchase agreements, however, are subject to ERA
review and approval.
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Fortis Turks and - In March 2011 Fortis Turks and Caicos submitted its 2010
Caicos annual regulatory filing outlining the Company's
performance in 2010. Included in the filing were the
calculations, in accordance with the utility's licence, of
rate base of US$142 million for 2010 and cumulative
shortfall in achieving allowable profits of US$49 million
as at December 31, 2010.
- In August 2011 Fortis Turks and Caicos filed with the
Interim Government of the Turks and Caicos Islands
("Interim Government") an Electricity Rate Variance
Application, which requested a change in the rate
structure and an overall approximate 6% increase in base
rates to government and commercial customers. Fortis Turks
and Caicos is currently in negotiations with the Interim
Government, which had approved in October 2011 an increase
in large hotel rates, which comprised approximately half
of the Company's overall requested increase in customer
rates. The Company made a counter proposal to the Interim
Government in January 2012 and expects a final
determination on the Electricity Rate Variance Application
by the end of the first quarter of 2012.
- An independent review of the regulatory framework for
the electricity sector in the Turks and Caicos Islands was
performed during the third quarter of 2011 on behalf of
the Interim Government. The purpose of the review was to:
(i) assess the effectiveness of the current regulatory
framework in terms of its administrative and economic
efficiency; (ii) assess the current and proposed
electricity costs and tariffs in the Turks and Caicos
Islands in relation to comparable regional and
international utilities; (iii) make recommendations for a
revised regulatory framework and Electricity Ordinance;
and (iv) make recommendations for the implementation and
operation of the revised regulatory framework. Fortis
Turks and Caicos provided a comprehensive response to the
Interim Government in January 2012 stating that the
Company supports limited mutually agreed upon reforms, but
that its current licenses must be respected and can only
be changed by mutual consent. Specifically, Fortis Turks
and Caicos would support reforms that strengthen the role
of the regulator in the rate-setting process and that are
fair to all stakeholders.
- Earlier in 2011 the Interim Government publicly stated
its intention to implement a carbon tax, effective
September 2011, that would be applicable to Fortis Turks
and Caicos but which may not be permitted to be passed on
to Fortis Turks and Caicos' customers. To date, no carbon
tax has been implemented. Under the terms of an agreement
with the Government of the Turks and Caicos Islands when
Fortis Turks and Caicos was granted its licence, the
Company is exempt from any taxes other than customs duties
where applicable by law.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the fourth quarter and year ended December 31, 2011, as compared to the same
periods in 2010, followed by a discussion of the nature of the variances in cash
flows.
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Summary of Consolidated Cash Flows (Unaudited)
Periods Ended
December 31 Quarter Year
($ millions) 2011 2010 Variance 2011 2010 Variance
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Cash, Beginning of
Period 108 64 44 109 85 24
Cash Provided by
(Used in):
Operating
Activities 227 198 29 904 732 172
Investing
Activities (369) (333) (36) (1,125) (991) (134)
Financing
Activities 124 180 (56) 201 283 (82)
Effect of Exchange
Rate Changes on
Cash and Cash
Equivalents (1) - (1) - - -
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Cash, End of Period 89 109 (20) 89 109 (20)
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $29 million higher quarter over quarter and $172
million higher year over year. The increases were mainly due to favourable
changes in working capital and higher earnings. Quarter over quarter, favourable
working capital changes associated with accounts receivable and inventories were
partially offset by unfavourable changes in accounts payable. The favourable
working capital changes year over year, associated primarily with accounts
payable, accounts receivable and inventories, were driven by the FortisBC Energy
companies and FortisAlberta.
Investing Activities: Cash used in investing activities was $36 million higher
quarter over quarter. The increase was due to a $49 million deferred payment
being made in December 2011, in accordance with an agreement, associated with
FHI's acquisition of FEVI in 2002. The deferred payment was originally
classified in long-term other liabilities. Cash used in investing activities
also increased as a result of the acquisition of the Hilton Suites Winnipeg
Airport hotel in 2011. The increases were partially offset by higher proceeds
from the sale of utility capital assets associated with the sale of joint-use
poles at Newfoundland Power in October 2011.
Cash used in investing activities was $134 million higher year over year. The
increase was due to the same reasons as discussed above for the quarter, as well
as higher capital spending related to the non-regulated Waneta hydroelectric
generation expansion project ("Waneta Expansion Project") and higher capital
spending at FortisAlberta, partially offset by lower capital spending at
FortisBC Electric.
Financing Activities: Cash provided by financing activities was $56 million
lower quarter over quarter, due to: (i) lower proceeds from long-term debt; (ii)
higher repayments of short-term borrowings; and (iii) lower advances from
non-controlling interests in the Waneta Expansion Limited Partnership ("Waneta
Partnership"), partially offset by lower repayments of both long-term debt and
committed credit facility borrowings classified as long-term.
Cash provided by financing activities was $82 million lower year over year, due
to: (i) lower proceeds from the issuance of preference shares; (ii) lower
proceeds from long-term debt; (iii) higher repayments of short-term borrowings;
(iv) higher repayments of committed credit facility borrowings classified as
long-term; and (v) higher common share dividends, partially offset by: (i)
higher proceeds from the issuance of common shares; (ii) lower repayments of
long-term debt; and (iii) higher advances from non-controlling interests in the
Waneta Partnership.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to allow the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt offerings. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40%
equity, including preference shares, and 60% debt, as well as investment-grade
credit ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in the
utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
December 31, 2011 December 31, 2010
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash)
(1) 5,855 55.0 5,914 58.4
Preference shares (2) 912 8.6 912 9.0
Common shareholders' equity 3,877 36.4 3,305 32.6
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Total (3) 10,644 100.0 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 improvement in the capital structure was driven by the public offering of
approximately $341 million of common shares in June and July 2011, combined with
common shares issued under the Corporation's dividend reinvestment and stock
option plans, and the reclassification of net unrealized foreign currency
translation losses related to the Corporation's previous investment in Belize
Electricity to long-term other assets. Also contributing to the improvement were
net earnings attributable to common equity shareholders, net of dividends,
combined with an overall decrease in total debt. A portion of the proceeds from
the public common equity offering were used to repay credit facility borrowings
in 2011.
Credit Ratings: The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit rating)
DBRS A(low) (unsecured debt credit rating)
During the third quarter of 2011, DBRS confirmed the Corporation's existing debt
credit rating at A(low). S&P is expected to complete its annual review of the
Corporation's credit rating in the first quarter of 2012. 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 approximate $1.2 billion in gross capital expenditures by
segment for 2011 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year Ended December 31, 2011
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other Regu-
Regu- lated
lated Total Elec-
Elec- Regu- tric
tric lated Utili- Non-
Utili- Utili- ties Regu-
FortisBC New- ties ties - lated Fortis
Energy Fortis found- - - Carib- - Pro-
Com- Alberta FortisBC land Cana- Cana- bean Utility per-
panies (2) Electric Power dian dian (3) (4) ties Total
----------------------------------------------------------------------------
253 416 102 81 47 899 71 174 30 1,174
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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 restorationexpenditures, net of salvage proceeds, for those
utilities where such expenditures are permissible in rate base in
2011.Excludes capitalized amortization and non-cash equity component of
AFUDC.
(2) Includes payments made to AESO for investment in transmission-related
capital projects
(3) Includes capital expenditures at Belize Electricity up to June 20, 2011
(4) Includes non-regulated generation, mainly related to the Waneta
Expansion Project, and corporate capital expenditures
Gross consolidated capital expenditures of $1,174 million for 2011 were $38
million lower than $1,212 million forecasted for 2011, as 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. Lower-than-forecasted
capital spending was mainly due to: (i) a shift in the timing of certain capital
expenditures from 2011 to 2012 and various individually small capital projects
determined not to be required at the FortisBC Energy companies; (ii) the
discontinuance of the consolidation method of accounting for Belize Electricity,
effective June 2011; and (iii) a shift in capital expenditures from 2011 to 2012
related to the timing of payments associated with the Waneta Expansion Project.
An update on significant capital projects for 2011 from that disclosed in the
MD&A as at December 31, 2010 is provided below.
FEVI's construction of the estimated $212 million 1.5 billion-cubic foot LNG
storage facility at Mount Hayes on Vancouver Island was completed in the second
quarter of 2011 and was brought online in late 2011. The storage facility
provides a reliable, cost-competitive means of storing gas close to customers,
while reducing the dependence on out-of-province storage facilities. The
facility provides greater flexibility to meet customer needs during winter
months when demand for natural gas is at its highest and meet planned and
unplanned system interruptions.
FEI's Customer Care Enhancement Project, at an estimated total project cost of
$110 million, was put into service in January 2012. The Company estimates
approximately $30 million of the project cost to be incurred in the first half
of 2012 related to final contractor payments with the total project cost
expected to come in under budget. The project entailed the insourcing of core
elements of FEI's customer care services, including two company-owned call
centres and billing operations, and implementation of a new customer information
system. The BCUC approved the project upon the Company's acceptance of a cost
risk-sharing condition, whereby FEI agreed to equally share with customers any
costs or savings outside a band of plus or minus 10% of the approved total
project cost.
FortisBC Electric's $105 million Okanagan Reinforcement Project was
substantially completed in the fall of 2011. The project related to upgrading
the existing overhead transmission line between Penticton and Vaseux Lake, near
Oliver, from 161 kilovolts ("kV") to a double-circuit 230-kV line and building a
new 230-kV terminal substation in the Oliver area.
The Fraser River South Bank South Arm Rehabilitation Project involved the
installation and replacement of underwater transmission pipeline crossings that
were at potential risk of failure from a major seismic event. During 2010
difficulties were experienced with one of the directional drills delaying the
project that was subsequently completed and came into service in 2011, rather
than in 2010 as originally expected, at an estimated total cost of approximately
$36 million.
During the first quarter of 2011, FortisAlberta substantially completed its $126
million Automated Metering Project, which involved the replacement of
approximately 477,000 conventional meters.
During 2011 FortisAlberta continued with the replacement of vintage poles under
its Pole Management Program, which involves 96,000 poles in total, to prevent
risk of failure due to age. The total capital cost of the program through to
2019 is now expected to be approximately $335 million, an increase from the $283
million forecast as at December 31, 2010. The increase is primarily due to a
revised forecast estimating higher labour and material costs later in the
program and a change in the program scope to include minor-line rebuilds.
Fortis Turks and Caicos had an agreement with a supplier to purchase two
diesel-powered generating units, each with a capacity of 9 MW. The units were
delivered in 2010 and 2011. Assuming demand for additional generating capacity
in 2014, an additional 9-MW unit is forecast for delivery at an estimated cost
of approximately $8 million (US$8 million). An agreement for the additional unit
has not yet been formalized as it is dependent on future demand trends.
In August 2011 Fortis Properties received municipal government approval to
construct a $47 million 12-storey office building in downtown St. John's,
Newfoundland. The building will feature 152,000 square feet of Class A office
space and include 261 parking spaces. Construction is expected to be completed
in the second half of 2013.
Construction progress on the $900 million 335-MW Waneta Expansion Project, in
partnership with Columbia Power Corporation and Columbia Basin Trust, is going
well and the project is currently on schedule. Fortis owns a 51% interest in the
Waneta Partnership and will operate and maintain the non-regulated investment
when the facility comes into service, which is expected in spring 2015. Major
construction activities on-site include excavation of the intake, powerhouse and
power tunnels. Approximately $244 million has been spent on this project since
construction began late 2010. The Waneta Expansion Project will be included in
the Canal Plant Agreement and will receive fixed energy and capacity
entitlements based upon long-term average water flows, thereby significantly
reducing hydrologic risk associated with the project. The energy, approximately
630 GWh, and associated capacity required to deliver such energy, for the Waneta
Expansion Project will be sold to BC Hydro under a long-term energy purchase
agreement. The surplus capacity, equal to 234 MW on an average annual basis, is
expected to be sold to FortisBC Electric under a long-term capacity purchase
agreement.
Over the five-year period 2012 through 2016, consolidated gross capital
expenditures are expected to be approximately $5.5 billion. Approximately 64% of
the capital spending is expected to be incurred at the regulated electric
utilities, driven by FortisAlberta and FortisBC Electric. Approximately 23% and
13% of the capital spending is expected to be incurred at the regulated gas
utilities and at the non-regulated operations, respectively. Capital
expenditures at the regulated utilities are subject to regulatory approval. Over
the five-year period, on average annually, 39% of utility capital spending is
expected to be incurred to meet customer growth; 38% is expected to be incurred
to ensure continued and enhanced performance, reliability and safety of
generation, transmission and distribution assets (i.e., sustaining capital
expenditures); and 23% is expected to be incurred for facilities, equipment,
vehicles, information technology and other assets.
A breakdown of forecast gross consolidated capital expenditures by segment for
2012 is provided in the following table.
----------------------------------------------------------------------------
Forecast Gross Consolidated Capital Expenditures (Unaudited) (1)
Year Ending December 31, 2012
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Electri Regu- Elec-
c lated tric Non-
Utili- Utili- Utili- Regu-
FortisBC New- ties ties ties lated Fortis
Energy Fortis found- - - - - Pro-
Com- Alberta FortisBC land Cana- Cana- Carib- Utility per-
panies (2) Electric Power dian dian bean (3) ties Total
----------------------------------------------------------------------------
244 419 111 82 61 917 55 256 63 1,291
----------------------------------------------------------------------------
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(1) Relates to forecast cash payments to acquire or construct utility
capital assets, income producing properties and intangible assets, as
would be reflected in the consolidated statement of cash flows.
Includes forecast asset removal and site restoration expenditures, net
of salvage proceeds, for those utilities where such expenditures are
permissible in rate base in 2012. Excludes forecast capitalized
amortization and non-cash equity component of AFUDC.
(2) Includes forecast payments to be made to AESO for investment in
transmission-related capital projects
(3) Includes forecast non-regulated generation, mainly related to the
Waneta Expansion Project, and corporate capital expenditures
Significant individual capital projects for 2012 include the continuation of the
construction of the non-regulated Waneta Expansion Project for $254 million and
the 12-storey office building in St. John's, Newfoundland for $32 million, as
well as the continued replacement of vintage poles under FortisAlberta's Pole
Management Program for $27 million.
CREDIT FACILITIES
As at December 31, 2011, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.2 billion, of which $1.9 billion was
unused, including the Corporation's unused $800 million committed revolving
credit facility. The credit facilities are syndicated mostly with the seven
largest Canadian banks, with no one bank holding more than 20% of these
facilities. Approximately $2.1 billion of the total credit facilities are
committed facilities with maturities ranging from 2012 to 2015.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities (Unaudited) As at
December December
Corporate Regulated Fortis 31, 31,
($ millions) and Other Utilities Properties 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit
facilities 845 1,390 13 2,248 2,109
Credit facilities
utilized:
Short-term
borrowings - (157) (2) (159) (358)
Long-term debt
(including current
portion) - (74) - (74) (218)
Letters of credit
outstanding (1) (65) - (66) (124)
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Credit facilities
unused 844 1,094 11 1,949 1,409
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FUTURE ACCOUNTING CHANGES
Adoption of New Accounting Standards: Due to continued uncertainty around the
adoption of a rate-regulated accounting standard by the International Accounting
Standards Board, Fortis has evaluated the option of adopting US GAAP, as opposed
to International Financial Reporting Standards ("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 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 currently not an SEC Issuer. Therefore, on
June 6, 2011, the Corporation filed an application with the Ontario Securities
Commission ("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 refers to US GAAP for
guidance on accounting for rate-regulated activities. The adoption of US GAAP in
2012 is, therefore, expected to result in fewer significant changes to the
Corporation's accounting policies as compared to accounting policy changes that
may have resulted from the adoption of IFRS. US GAAP guidance on accounting for
rate-regulated activities allows the economic impact of rate-regulated
activities to be recognized in the consolidated financial statements in a manner
consistent with the timing by which amounts are reflected in customer rates.
Fortis believes that the continued application of rate-regulated accounting, and
the associated recognition of regulatory assets and liabilities under US GAAP,
accurately reflects the impact that rate regulation has on the Corporation's
consolidated financial position and results of operations.
During the fourth quarter of 2010, the Corporation developed a three-phase plan
to adopt US GAAP effective January 1, 2012. The following is an overview of the
activities under each phase and their current status.
Phase I - Scoping and Diagnostics: Phase I consisted of project initiation and
awareness, project planning and resourcing, and identification of high-level
differences between US GAAP and Canadian GAAP in order to highlight areas where
detailed analysis would be needed to determine and conclude as to the nature and
extent of financial statement impacts. External accounting and legal advisors
were engaged during this phase to assist the Corporation's internal US GAAP
conversion team and to provide technical input and expertise as required. Phase
I commenced in the fourth quarter of 2010 and was completed during 2011.
Phase II - Analysis and Development: Phase II consisted 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 US 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 were no longer required or applicable as a result of the Exemption
granted by the OSC as discussed above.
Phase II of the plan commenced in January 2011 and was essentially completed
during 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 result in additional disclosure requirements. The impact on
information systems and internal controls over financial reporting is expected
to be minimal.
Phase III - Implementation and Review: Phase III is currently ongoing and has
involved the implementation of financial reporting systems and internal control
changes required by the Corporation to prepare and file its consolidated
financial statements in accordance with US GAAP beginning in 2012, and the
communication of associated impacts.
The Corporation will prepare and file its audited Canadian GAAP consolidated
financial statements for the year ended December 31, 2011 in the usual manner.
The Corporation then intends to voluntarily prepare and file audited US GAAP
consolidated financial statements for the year ended December 31, 2011, with
2010 comparatives. The Corporation's voluntary filing of audited US GAAP
consolidated financial statements for the year ended December 31, 2011,
subsequent to the filing of its audited Canadian GAAP consolidated financial
statements for the year ended December 31, 2011, has been approved by the OSC
and is expected to be completed by March 31, 2012. Beginning with the first
quarter of 2012, the Corporation's unaudited interim consolidated financial
statements will be prepared and filed in accordance with US GAAP.
Phase III will conclude when the Corporation files its annual audited
consolidated financial statements for the year ending December 31, 2012 prepared
in accordance with US GAAP.
Financial Statement Impacts - US GAAP: The areas identified to date where
differences between US GAAP and Canadian GAAP are expected to have the most
significant financial statement impacts are outlined below. The identified
impacts are unaudited and are subject to change based on further analysis.
Employee future benefits: Under Canadian GAAP, the accrued benefit asset or
liability associated with defined benefit plans is recognized on the balance
sheet with a reconciliation of the recognized asset or liability to the funded
or unfunded status being disclosed in the notes to the consolidated financial
statements. The accrued benefit asset or liability excludes unamortized balances
related to past service costs, actuarial gains and losses and transitional
obligations which have not yet been recognized.
US GAAP requires recognition of the funded status of defined benefit plans on
the balance sheet. Unamortized balances related to past service costs, actuarial
gains and losses and transitional obligations or assets are separately
recognized on the balance sheet as a component of accumulated other
comprehensive income or, in the case of entities with activities subject to rate
regulation, as regulatory assets or liabilities for recovery from, or refund to,
customers in future rates. Subsequent changes to past service costs, actuarial
gains and losses and transitional obligations would be recognized as part of
pension expense, where required by the regulator, or otherwise as a change in
the regulatory asset or liability. Therefore, upon adoption of US GAAP, the
Corporation's rate-regulated subsidiaries will recognize the funded status of
their defined benefit pension plans on the balance sheet with the above-noted
unamortized balances recognized as regulatory assets or liabilities.
US GAAP also requires that OPEB costs be recorded on an accrual basis, and
prohibits the recognition of regulatory assets or liabilities associated with
OPEB costs that are recovered on a cash basis. FortisAlberta has historically
recovered its OPEB costs on a cash basis, as opposed to an accrual basis, and
will likely continue to do so as ordered by its regulator. Therefore,
FortisAlberta's regulatory asset associated with OPEB costs does not meet the
criteria for recognition under US GAAP. Historically, Newfoundland Power had
also recovered its OPEB costs on a cash basis. However, in December 2010, the
regulator approved Newfoundland Power's application to: (i) adopt the accrual
method of accounting for OPEB costs, effective January 1, 2011; (ii) recover the
transitional regulatory asset associated with the adoption of accrual accounting
over a 15-year period; and (iii) adopt an OPEB cost-variance deferral account to
capture differences between OPEB expense calculated in accordance with
applicable generally accepted accounting principles and OPEB expense approved by
the regulator for rate-setting purposes. The rules under US GAAP related to
accounting for OPEBs by rate-regulated entities require that Newfoundland Power
de-recognize its OPEB regulatory asset as at January 1, 2010 on the premise
that, as at that date, Newfoundland Power was recovering its OPEB costs on a
cash basis. However, the regulatory asset will be re-recognized through earnings
in accordance with US GAAP in 2010 based on the regulator's approval of
Newfoundland Power's application to adopt the accrual method of accounting for
OPEBs effective January 1, 2011 and to recover the associated transitional
regulatory asset over a 15-year period.
Additional differences between Canadian GAAP and US GAAP in terms of accounting
for defined benefit plans include the determination of the measurement date and
the attribution period over which pension expense is recognized. Canadian GAAP
allows for the use of a measurement date up to three months prior to the date of
an entity's fiscal year end. However, US GAAP requires the entity's fiscal year
end to be used as the measurement date. Canadian GAAP also allows for the use of
an attribution period for defined benefit pension plans, under specific
circumstances, that extends beyond the date when the credited service period
ends. However, US GAAP allows for the use of an attribution period for defined
benefit pension plans up to the date when credited service ends. The differences
are expected to impact the calculation of the Corporation's consolidated benefit
obligation, which will be mostly offset by a corresponding change to regulatory
assets or liabilities.
With the exception of a one-time adjustment with respect to Newfoundland Power's
inability to recognize its OPEB regulatory asset as at January 1, 2010 and its
ability to subsequently re-recognize this OPEB regulatory asset through earnings
in 2010, the impact of adopting US GAAP with respect to accounting for employee
future benefits is not expected to have a material impact on the Corporation's
consolidated earnings.
Brilliant Power Purchase Agreement ("BPPA"): FortisBC Electric expects that its
BPPA will be accounted for as a capital lease under US GAAP. While the
requirement to evaluate whether an arrangement includes a lease is similar
between Canadian GAAP and US GAAP, the effective date for prospective adoption
of lease accounting guidance differs, resulting in an accounting difference with
respect to the BPPA.
Fulfillment of the BPPA is dependent on the use of a specific asset, the
Brilliant Hydroelectric Plant ("Brilliant"), and the conveyance unto FortisBC
Electric of the right to use that asset under an arrangement between FortisBC
Electric and the legal owner of Brilliant. The BPPA qualifies as a capital lease
as the present value of the minimum lease payments to be made by FortisBC
Electric represents recovery of the entire amount of the initial investment in
Brilliant by the legal owner over the term of the arrangement.
The anticipated effect of retrospectively recognizing Brilliant as a capital
lease upon adoption of US GAAP includes the recognition on the consolidated
balance sheet of a utility capital asset with a corresponding capital lease
obligation for an equivalent amount. Each subsequent reporting period, the total
amount of amortization and interest expense to be recognized under capital lease
accounting is expected to differ from the amount paid under the BPPA and
recovered through current electricity rates as permitted by the BCUC. This
timing difference is expected to be recognized as a regulatory asset, with
amounts recovered through electricity rates expected to equal the combined
amount of the capitalized lease asset and interest on the lease obligation over
the term of the BPPA.
Since US GAAP allows for entities to account for the effects of rate regulation,
the impact of adopting capital lease accounting for Brilliant is not expected to
affect the Corporation's consolidated earnings.
Lease-In Lease-Out ("LILO") Transactions: FEI had entered into arrangements
whereby certain natural gas distribution assets were leased to certain
municipalities and then leased back by FEI from the municipalities. Under
Canadian GAAP, the lease of the assets to the municipalities has been accounted
for as a sales-type lease and the lease back of the assets as an operating
lease. Gains recorded on the lease out of the assets were deferred and are being
amortized over the term of the lease back arrangements.
Under US GAAP, the natural gas distribution assets are considered to be
equipment integral to FEI's operations and, therefore, must be evaluated as a
real estate sale-leaseback transaction. As a result of this evaluation, the
transaction is required to be accounted for as a financing transaction under US
GAAP. Under the financing method, the assets subject to the sale-leaseback
arrangement are to be recorded as utility capital assets on the Corporation's
consolidated balance sheet and subsequently depreciated. Sale proceeds received
are recorded as long-term debt. Lease payments, less the portion considered to
be interest expense, decrease the long-term debt. The deferred gains, and
amortization thereof, which were recorded in accordance with Canadian GAAP are
not recognized under US GAAP.
The retrospective impact of accounting for FEI's LILO transactions under US GAAP
is expected to result in a decrease in opening retained earnings as at January
1, 2010. The impact on the Corporation's consolidated earnings is not expected
to be material.
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 First Preference Shares, Series C and Series E do not meet
the criteria for recognition as a financial liability. Therefore, upon the
adoption of US GAAP, the Corporation will reclassify its First Preference
Shares, Series C and Series E from long-term liabilities to shareholders' equity
on the consolidated balance sheet. The associated dividends will not be recorded
as finance charges on the Corporation's consolidated statement of earnings but,
rather, will be recorded as earnings attributable to preference equity
shareholders.
Corporate income taxes: Under Canadian GAAP, the Corporation has calculated and
recognized corporate income taxes using substantively enacted corporate income
tax rates. Under US GAAP, the Corporation is required to calculate and record
corporate income taxes based on enacted corporate income tax rates. Therefore,
upon adoption of US GAAP, the Corporation will be required to recognize the
impact of the difference between enacted tax rates and substantively enacted tax
rates related to the calculation of Part VI.1 tax deductions associated with
preference share dividends. The retrospective adjustment to recognize the Part
VI.1 tax deductions based on enacted corporate income tax rates will result in a
reduction in opening retained earnings under US GAAP and annual earnings
thereafter. However, the adjustments are expected to reverse once pending
Canadian federal legislation is passed and proposed corporate income tax rate
changes become enacted.
The above items do not represent a complete list of expected differences between
US GAAP and Canadian GAAP and are subject to change. Other less significant
differences have also been identified. Analysis also remains ongoing and
additional areas where the Corporation's consolidated financial statements could
be materially impacted may be identified prior to the Corporation's voluntary
preparation and filing of its audited US GAAP consolidated financial statements
for the year ended December 31, 2011. A detailed reconciliation between the
Corporation's audited Canadian GAAP and US GAAP financial statements for 2011,
including 2010 comparatives, will be disclosed as part of that voluntary filing.
The unaudited estimated quantification and reconciliation of the Corporation's
consolidated balance sheets as at December 31, 2011 and December 31, 2010,
prepared in accordance with US GAAP versus Canadian GAAP, based on the
differences identified to date, may be summarized as follows.
Total assets as at December 31, 2011 are estimated to increase by approximately
$597 million (December 31, 2010 - $496 million). The estimated increase is due
primarily to expected increases in regulatory assets and utility capital assets
in accordance with US GAAP.
Total liabilities as at December 31, 2011 are estimated to increase by
approximately $329 million (December 31, 2010 - $226 million). The estimated
increase is due primarily to the expected increases in long-term debt and
capital lease obligations and pension liabilities in accordance with US GAAP,
partially offset by the reclassification of preference shares from liabilities
to shareholders' equity.
Shareholders' equity as at December 31, 2011 is estimated to increase by
approximately $268 million (December 31, 2010 - $270 million). The estimated
increase is due primarily to the expected reclassification of preference shares
from liabilities to shareholders' equity in accordance with US GAAP, partially
offset by an estimated reduction in retained earnings of approximately $35
million (December 31, 2010 - $28 million), an estimated increase in accumulated
other comprehensive loss of approximately $21 million (December 31, 2010 - $14
million) and other miscellaneous reductions in shareholders' equity based on the
retrospective application of US GAAP. Approximately half of the reduction in
retained earnings results from higher corporate income taxes, as referred to
above, and is expected to reverse in a future period once pending Canadian
federal income tax legislation is passed and proposed Part VI.1 tax rate changes
become enacted.
As previously indicated, and subject to the above referenced one-time adjustment
with respect to Newfoundland Power's inability to recognize its OPEB regulatory
asset as at January 1, 2010 and its subsequent ability to re-recognize this OPEB
regulatory asset in 2010, no material adjustments to the Corporation's
consolidated earnings are currently expected under US GAAP due to the
Corporation's continued ability to apply rate-regulated accounting policies.
The unaudited estimated quantification and reconciliation of the Corporation's
consolidated statements of earnings for the years ended December 31, 2011 and
December 31, 2010, prepared in accordance with US GAAP versus Canadian GAAP,
based on the differences identified to date, may be summarized as follows.
Year ended December 31, 2011: Consolidated net earnings to be recognized in
accordance with US GAAP are estimated to increase by $10 million (from $356
million to $366 million). The estimated increase is due primarily to the
reclassification of preference share dividends totalling $17 million, in
accordance with US GAAP, from finance charges to earnings attributable to
preference equity shareholders, partially offset by an expected reduction in
earnings attributable to common equity shareholders of approximately $7 million.
Year ended December 31, 2010: Consolidated net earnings to be recognized in
accordance with US GAAP, prior to the one-time adjustment to re-recognize
Newfoundland Power's OPEB regulatory asset, are estimated to increase by
approximately $8 million (from $323 million to $331 million). The estimated
increase is due primarily to the reclassification of preference share dividends
totaling $17 million, in accordance with US GAAP, from finance charges to
earnings attributable to preference equity shareholders, partially offset by an
expected reduction in earnings attributable to common equity shareholders of
approximately $9 million.
The one-time, non-recurring adjustment to re-recognize Newfoundland Power's OPEB
regulatory asset in 2010 is estimated to increase earnings attributable to
common equity shareholders for the year ended December 31, 2010 by approximately
$46 million. This adjustment is not expected to impact retained earnings as at
December 31, 2010, as compared to retained earnings reported in accordance with
Canadian GAAP as at December 31, 2010, as it reverses an adjustment made to
derecognize the OPEB regulatory asset upon adoption of US GAAP as at January 1,
2010.
OUTLOOK
The Corporation's significant capital expenditure program, which is expected to
be approximately $5.5 billion over the five-year period 2012 through 2016,
should support continuing 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.
FORTIS INC.
Consolidated Financial Statements
For the three and twelve months ended December 31, 2011 and 2010
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at December 31
(in millions of Canadian dollars)
2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 89 $ 109
Accounts receivable 644 655
Prepaid expenses 19 17
Regulatory assets 210 241
Inventories 134 168
Future income taxes 24 14
------------------------------
1,120 1,204
Assets held for sale - 45
Other assets 270 168
Regulatory assets 985 854
Future income taxes 8 16
Utility capital assets 8,687 8,185
Income producing properties 594 560
Intangible assets 341 324
Goodwill 1,557 1,553
------------------------------
$ 13,562 $ 12,909
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings $ 159 $ 358
Accounts payable and accrued charges 914 953
Dividends payable 60 54
Income taxes payable 33 30
Regulatory liabilities 43 60
Current installments of long-term debt and
capital lease obligations 106 56
Future income taxes 5 6
------------------------------
1,320 1,517
Other liabilities 323 308
Regulatory liabilities 558 467
Future income taxes 685 629
Long-term debt and capital lease obligations 5,679 5,609
Preference shares 320 320
------------------------------
8,885 8,850
------------------------------
Shareholders' equity
Common shares 3,032 2,578
Preference shares 592 592
Contributed surplus 14 12
Equity portion of convertible debentures - 5
Accumulated other comprehensive loss (74) (94)
Retained earnings 905 804
------------------------------
4,469 3,897
Non-controlling interests 208 162
------------------------------
4,677 4,059
------------------------------
$ 13,562 $ 12,909
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Year Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 1,037 $ 1,034 $ 3,747 $ 3,657
----------------------------------------
Expenses
Energy supply costs 490 507 1,697 1,686
Operating 237 228 865 822
Amortization 108 103 419 410
----------------------------------------
835 838 2,981 2,918
----------------------------------------
Operating income 202 196 766 739
Other income (expenses), net 6 6 40 13
Finance charges 90 89 370 362
----------------------------------------
Earnings before corporate taxes 118 113 436 390
Corporate taxes 23 19 80 67
----------------------------------------
Net earnings $ 95 $ 94 $ 356 $ 323
----------------------------------------
----------------------------------------
Net earnings attributable to:
Non-controlling interests $ 2 $ 2 $ 9 $ 10
Preference equity shareholders 7 7 29 28
Common equity shareholders 86 85 318 285
----------------------------------------
$ 95 $ 94 $ 356 $ 323
----------------------------------------
----------------------------------------
Earnings per common share
Basic $ 0.46 $ 0.49 $ 1.75 $ 1.65
Diluted $ 0.45 $ 0.47 $ 1.74 $ 1.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, beginning of period $ 877 $ 770 $ 804 $ 763
Net earnings attributable to
common and preference equity
shareholders 93 92 347 313
--------------------------------------------
970 862 1,151 1,076
Dividends on common shares (58) (51) (217) (244)
Dividends on preference shares
classified as equity (7) (7) (29) (28)
--------------------------------------------
Balance, end of period $ 905 $ 804 $ 905 $ 804
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 95 $ 94 $ 356 $ 323
----------------------------------------
----------------------------------------
Other comprehensive (loss) income
Unrealized foreign currency
translation (losses) gains on net
investments in self-sustaining
foreign operations (18) (20) 10 (33)
Gains (losses) on hedges of net
investments in self-sustaining
foreign operations 17 17 (10) 25
Corporate tax (expense) recovery (2) (3) 2 (4)
----------------------------------------
Unrealized foreign currency
translation (losses) gains, net of
hedging activities and tax (3) (6) 2 (12)
Reclassification of unrealized
foreign currency translation
losses, net of hedging activities
and tax, related to Belize
Electricity - - 17 -
Reclassification to earnings of net
losses on derivative instruments
discontinued as cash flow hedges,
net of tax - - 1 1
----------------------------------------
(3) (6) 20 (11)
----------------------------------------
Comprehensive income $ 92 $ 88 $ 376 $ 312
----------------------------------------
----------------------------------------
Comprehensive income attributable
to:
Non-controlling interests $ 2 $ 2 $ 9 $ 10
Preference equity shareholders 7 7 29 28
Common equity shareholders 83 79 338 274
----------------------------------------
$ 92 $ 88 $ 376 $ 312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 95 $ 94 $ 356 $ 323
Items not affecting cash:
Amortization - utility capital
assets and income producing
properties 98 92 380 368
Amortization - intangible
assets 11 10 42 40
Amortization - other (1) 1 (3) 2
Future income taxes 1 (2) 4 (3)
Accrued employee future
benefits 5 3 18 8
Equity component of allowance
for funds used during
construction (4) (5) (13) (15)
Other (9) (2) (4) 2
Change in long-term regulatory
assets and liabilities 35 13 26 9
--------------------------------------------
231 204 806 734
Change in non-cash operating
working capital (4) (6) 98 (2)
--------------------------------------------
227 198 904 732
--------------------------------------------
Investing activities
Change in other assets and other
liabilities (47) (1) (52) -
Capital expenditures - utility
capital assets (339) (336) (1,086) (1,008)
Capital expenditures - income
producing properties (10) (5) (30) (19)
Capital expenditures -
intangible assets (19) (29) (58) (46)
Contributions in aid of
construction 26 26 75 67
Proceeds on sale of utility
capital assets and income
producing properties 45 12 51 15
Business acquistion, net of cash
acquired (25) - (25) -
--------------------------------------------
(369) (333) (1,125) (991)
--------------------------------------------
Financing activities
Change in short-term borrowings (84) (52) (198) (56)
Proceeds from long-term debt,
net of issue costs 304 523 343 523
Repayments of long-term debt and
capital lease obligations (12) (114) (36) (329)
Net (repayments) borrowings
under committed credit
facilities (40) (185) (145) 8
Advances from non-controlling
interests 4 44 81 45
Issue of common shares, net of
costs and
dividends reinvested 4 7 345 22
Issue of preference shares, net
of costs - - - 242
Dividends
Common shares, net of
dividends reinvested (42) (33) (151) (135)
Preference shares (7) (7) (29) (28)
Subsidiary dividends paid to
non-controlling interests (3) (3) (9) (9)
--------------------------------------------
124 180 201 283
--------------------------------------------
Effect of exchange rate changes
on cash and cash equivalents (1) - - -
--------------------------------------------
Change in cash and cash
equivalents (19) 45 (20) 24
Cash and cash equivalents,
beginning of period 108 64 109 85
--------------------------------------------
Cash and cash equivalents, end
of period $ 89 $ 109 $ 89 $ 109
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SEGMENTED INFORMATION (UNAUDITED)
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
Fortis-
Quarter BC
Ended Energy New-
December 31, Comp- Fortis found- Total Electric
2011 anies- Alb- Fortis-BC land Other Electric Carib-
($ millions) Canadian erta Electric Power Canadian Canadian bean
----------------------------------------------------------------------------
Revenue 477 102 81 156 84 423 70
Energy supply
costs 264 - 22 103 55 180 46
Operating
expenses 88 37 25 20 15 97 9
Amortization 30 34 11 11 6 62 8
----------------------------------------------------------------------------
Operating
income 95 31 23 22 8 84 7
Other income
(expenses),
net 2 2 - - - 2 1
Finance
charges 30 16 10 9 4 39 4
Corporate tax
expense
(recovery) 16 - 2 4 - 6 -
----------------------------------------------------------------------------
Net earnings
(loss) 51 17 11 9 4 41 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-
controlling
interests - - - 1 - 1 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 51 17 11 8 4 40 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable
assets 4,408 2,452 1,320 1,202 658 5,632 718
----------------------------------------------------------------------------
Total assets 5,316 2,679 1,541 1,202 721 6,143 856
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 74 163 24 26 14 227 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
December 31,
2010
($ millions)
----------------------------------------------------------------------------
Revenue 479 99 73 152 87 411 84
Energy supply
costs 277 - 23 102 59 184 52
Operating
expenses 87 37 21 15 12 85 13
Amortization 27 32 10 12 5 59 9
----------------------------------------------------------------------------
Operating
income 88 30 19 23 11 83 10
Other income
(expenses),
net 3 1 1 - - 2 1
Finance
charges 31 14 9 9 5 37 6
Corporate tax
expense
(recovery) 15 - 1 4 1 6 -
----------------------------------------------------------------------------
Net earnings
(loss) 45 17 10 10 5 42 5
Non-
controlling
interests - - - 1 - 1 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 45 17 10 9 5 41 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 134
Identifiable
assets 4,319 2,144 1,263 1,197 646 5,250 779
----------------------------------------------------------------------------
Total assets 5,227 2,371 1,484 1,197 709 5,761 913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 71 121 40 22 15 198 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
-------------------------------------
Quarter
Ended
December 31, Fortis Fortis Inter-
2011 Gene- Prope- Corporate segment
($ millions) ration rties and Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 9 58 7 (7) 1,037
Energy supply
costs - - - - 490
Operating
expenses 2 39 3 (1) 237
Amortization 1 5 2 - 108
----------------------------------------------------------------------------
Operating
income 6 14 2 (6) 202
Other income
(expenses),
net - - 1 - 6
Finance
charges - 6 17 (6) 90
Corporate tax
expense
(recovery) 1 3 (3) - 23
----------------------------------------------------------------------------
Net earnings
(loss) 5 5 (11) - 95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-
controlling
interests - - - - 2
Preference
share
dividends - - 7 - 7
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 5 (18) - 86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable
assets 542 614 482 (391) 12,005
----------------------------------------------------------------------------
Total assets 542 614 482 (391) 13,562
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 43 10 - - 368
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
December 31,
2010
($ millions)
----------------------------------------------------------------------------
Revenue 9 57 7 (13) 1,034
Energy supply
costs - - - (6) 507
Operating
expenses 1 38 4 - 228
Amortization 1 5 2 - 103
----------------------------------------------------------------------------
Operating
income 7 14 1 (7) 196
Other income
(expenses),
net 1 - - (1) 6
Finance
charges 1 6 16 (8) 89
Corporate tax
expense
(recovery) 1 1 (4) - 19
----------------------------------------------------------------------------
Net earnings
(loss) 6 7 (11) - 94
Non-
controlling
interests - - - - 2
Preference
share
dividends - - 7 - 7
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 6 7 (18) - 85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,553
Identifiable
assets 344 576 505 (417) 11,356
----------------------------------------------------------------------------
Total assets 344 576 505 (417) 12,909
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 77 5 - - 370
----------------------------------------------------------------------------
----------------------------------------------------------------------------
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
Fortis
BC Total
Annual Energy New- Elec-
December 31, Companies Fortis found- tric Electric
2011 - Fortis BC land Other Cana- Carib-
($ millions) Canadian Alberta Electric Power Canadian dian bean
----------------------------------------------------------------------------
Revenue 1,568 409 296 573 339 1,617 305
Energy supply
costs 854 - 72 369 218 659 192
Operating
expenses 307 144 83 75 48 350 40
Amortization 111 134 45 42 24 245 33
----------------------------------------------------------------------------
Operating
income 296 131 96 87 49 363 40
Other income
(expenses),
net 10 5 1 - - 6 3
Finance
charges 127 60 39 36 20 155 14
Corporate tax
expense
(recovery) 40 1 10 16 7 34 1
----------------------------------------------------------------------------
Net earnings
(loss) 139 75 48 35 22 180 28
Non-
controlling
interests - - - 1 - 1 8
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 139 75 48 34 22 179 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 138
Identifiable
assets 4,408 2,452 1,320 1,202 658 5,632 718
----------------------------------------------------------------------------
Total assets 5,316 2,679 1,541 1,202 721 6,143 856
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 253 416 102 81 47 646 71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Annual
December 31,
2010
($ millions)
----------------------------------------------------------------------------
Revenue 1,546 385 266 555 331 1,537 333
Energy supply
costs 863 - 73 358 215 646 201
Operating
expenses 288 141 73 62 45 321 48
Amortization 108 126 41 47 23 237 36
----------------------------------------------------------------------------
Operating
income 287 118 79 88 48 333 48
Other income
(expenses),
net 9 3 3 - - 6 3
Finance
charges 121 54 35 36 21 146 18
Corporate tax
expense
(recovery) 45 (1) 5 16 8 28 1
----------------------------------------------------------------------------
Net earnings
(loss) 130 68 42 36 19 165 32
Non-
controlling
interests - - - 1 - 1 9
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 130 68 42 35 19 164 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 134
Identifiable
assets 4,319 2,144 1,263 1,197 646 5,250 779
----------------------------------------------------------------------------
Total assets 5,227 2,371 1,484 1,197 709 5,761 913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 253 379 139 78 48 644 72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------------
Inter-
Annual seg-
December 31, Fortis Fortis Corporate ment
2011 Gene- Prope- and elimi- Conso-
($ millions) ration rties Other nations lidated
-------------------------------------------------------------------------
Revenue 34 231 29 (37) 3,747
Energy supply
costs 1 - - (9) 1,697
Operating
expenses 8 156 10 (6) 865
Amortization 4 19 7 - 419
-------------------------------------------------------------------------
Operating
income 21 56 12 (22) 766
Other income
(expenses),
net 1 - 21 (1) 40
Finance
charges 2 24 71 (23) 370
Corporate tax
expense
(recovery) 2 9 (6) - 80
-------------------------------------------------------------------------
Net earnings
(loss) 18 23 (32) - 356
Non-
controlling
interests - - - - 9
Preference
share
dividends - - 29 - 29
-------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 18 23 (61) - 318
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Goodwill - - - - 1,557
Identifiable
assets 542 614 482 (391) 12,005
-------------------------------------------------------------------------
Total assets 542 614 482 (391) 13,562
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gross capital
expenditures
(1) 174 30 - - 1,174
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Annual
December 31,
2010
($ millions)
-------------------------------------------------------------------------
Revenue 36 226 29 (50) 3,657
Energy supply
costs 1 - - (25) 1,686
Operating
expenses 9 151 10 (5) 822
Amortization 4 18 7 - 410
-------------------------------------------------------------------------
Operating
income 22 57 12 (20) 739
Other income
(expenses),
net 4 - (5) (4) 13
Finance
charges 4 24 73 (24) 362
Corporate tax
expense
(recovery) 2 7 (16) - 67
-------------------------------------------------------------------------
Net earnings
(loss) 20 26 (50) - 323
Non-
controlling
interests - - - - 10
Preference
share
dividends - - 28 - 28
-------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 20 26 (78) - 285
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Goodwill - - - - 1,553
Identifiable
assets 344 576 505 (417) 11,356
-------------------------------------------------------------------------
Total assets 344 576 505 (417) 12,909
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gross capital
expenditures
(1) 84 19 1 - 1,073
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 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
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with
total assets of approximately $13.6 billion and fiscal 2011 revenue totalling
approximately $3.8 billion. The Corporation serves more than 2,000,000 gas and
electricity customers. Its regulated holdings include electric distribution
utilities in five Canadian provinces and two Caribbean countries and a natural
gas utility in British Columbia. Fortis owns and operates non-regulated
generation assets across Canada and in Belize and Upper New York State. It also
owns hotels and commercial office and retail space in Canada.
The Common Shares, First Preference Shares, Series C; First Preference Shares,
Series E; First Preference Shares, Series F; First Preference Shares, Series G;
and First Preference Shares, Series H of Fortis are traded on the Toronto Stock
Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and
FTS.PR.H, respectively.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2010 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
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