Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved net earnings
attributable to common equity shareholders of $285 million, or $1.65 per common
share, up $23 million from earnings of $262 million, or $1.54 per common share,
in 2009.
Performance for the year was driven by Canadian Regulated Utilities and
non-regulated hydroelectric generation operations. Tempering results year over
year were lower earnings from Caribbean Regulated Electric Utilities and higher
corporate expenses.
Fortis has raised its annualized dividend to common shareholders for 38
consecutive years, the record for a public corporation in Canada. Dividends paid
per common share were $1.12 in 2010, up 7.7% from $1.04 paid per common share in
the previous year. The dividend payout ratio was approximately 68% in 2010.
Fortis increased its quarterly common share dividend to 29 cents from 28 cents,
commencing with the first quarter dividend payable on March 1, 2011, which
translates into an annualized dividend of $1.16.
"For the second consecutive year our capital program surpassed $1 billion,
reaching a record approximate $1.1 billion in 2010," says Stan Marshall,
President and Chief Executive Officer, Fortis Inc. "The US$53 million
19-megawatt hydroelectric generating facility at Vaca in Belize was commissioned
last March and completes the three-phase hydroelectric development for the Macal
River. Several significant capital projects continued throughout 2010 and are
slated for completion in the coming months. FortisAlberta will substantially
complete its approximate $126 million multi-year Automated Meter Infrastructure
Project, which involves the replacement of some 466,000 conventional meters, by
the end of March 2011. FortisBC is on track to complete its $106 million
Okanagan Transmission Reinforcement Project, the largest capital project ever
undertaken by the utility, by mid-2011. At Terasen Gas (Vancouver Island),
construction of the $210 million liquefied natural gas storage facility is
expected to be completed during the second quarter of 2011, with the facility
coming into service by late 2011. A little further out on the horizon, in early
2012, the $110 million Customer Care Enhancement Project, currently underway at
Terasen Gas, is scheduled for completion," he explains.
In October 2010 Fortis, in partnership with Columbia Power Corporation and
Columbia Basin Trust, concluded definitive agreements to construct the $900
million 335-megawatt ("MW") Waneta Expansion hydroelectric generating facility
on the Pend d'Oreille River in British Columbia. Fortis owns a 51% controlling
interest in the non-regulated partnership, which has negotiated 40-year power
sales agreements with BC Hydro and FortisBC for the energy and capacity,
respectively, to be generated by the facility. Last fall, construction began on
the Waneta Expansion. Fortis will operate and maintain the facility when it
comes into service, which is expected in spring 2015. "British Columbia and the
Pacific Northwest region provide potential to pursue hydroelectric generation
assets that complement the utility operations of Fortis in western Canada and
deliver value to our customers and shareholders," says Marshall.
The Terasen Gas companies delivered earnings of $130 million, up $13 million
from $117 million for 2009. Approximately $9 million of the improvement in
earnings was due to the reversal in 2010, as approved by the regulator, of a
provision taken in the fourth quarter of 2009 for the project cost overrun
related to the conversion of Whistler customer appliances from propane to
natural gas. Earnings also increased as a result of the higher allowed rate of
return on common shareholders' equity ("ROE") at each of the Terasen Gas
companies, effective July 1, 2009, and an increase in the deemed common equity
component of the total capital structure at Terasen Gas, effective January 1,
2010.
Earnings at Canadian Regulated Electric Utilities were $164 million, up $15
million from $149 million for 2009. Excluding the favourable one-time $3 million
corporate tax adjustment at FortisOntario in 2009, earnings were up $18 million
year over year. The increase was driven by overall growth in electrical
infrastructure investment, the increase in the allowed ROE at FortisBC effective
January 1, 2010, customer growth at FortisAlberta, increased electricity sales
at Newfoundland Power, and improved performance at FortisOntario due to the
first full year of earnings' contribution from Algoma Power and lower effective
corporate income taxes. Earnings for the year, however, reflected additional
operating expenses of $1 million after tax at Newfoundland Power associated with
restoration work post Hurricane Igor, the impact of a weather-related decrease
in electricity sales at FortisBC and lower net transmission revenue at
FortisAlberta.
Caribbean Regulated Electric Utilities contributed $23 million to earnings
compared to $27 million for 2009. The decrease was largely due to the
unfavourable impact of foreign currency translation and poor financial
performance at Belize Electricity where regulatory challenges continue to impede
the utility's ability to earn a fair and reasonable return. In 2010 the utility
contributed just $1.5 million to earnings of Fortis. In the course of normal
operations, Belize Electricity would be expected to contribute approximately $10
million annually to the Corporation's consolidated earnings. Results for 2010
also reflected continued lower-than-average annual electricity sales growth, due
to persistent challenging economic conditions in the Caribbean region and the
negative effect on air conditioning load of cooler-than-normal temperatures
experienced on Grand Cayman in the second half of 2010. Annualized electricity
sales growth for Caribbean Regulated Electric Utilities was 0.9% in 2010
compared to 2% in 2009.
Non-Regulated Fortis Generation contributed $20 million to earnings, up $4
million from 2009 mainly due to increased hydroelectric production in Belize, as
a result of the commissioning of the 19-MW Vaca facility in March 2010 and
higher rainfall, and lower finance charges, partially offset by lower earnings
from the Rankine hydroelectric generating facility in Ontario due to the expiry
of the water rights in April 2009.
Fortis Properties delivered earnings of $26 million, up $2 million from 2009
mainly due to lower effective corporate income taxes.
Corporate and other expenses were $78 million compared to $71 million for 2009.
The increase was due to dividends associated with the $250 million First
Preference Shares, Series H issued in January 2010 and business development
costs, partially offset by lower finance charges.
Earnings for the fourth quarter were $85 million, or $0.49 per common share, up
from $81 million, or $0.48 per common share, for the same quarter in 2009. The
increase was mainly due to improved performance at Canadian Regulated Electric
Utilities, non-regulated hydroelectric generation operations in Belize and lower
effective corporate income taxes at Fortis Properties, partially offset by lower
earnings from the Terasen Gas companies and Caribbean Regulated Electric
Utilities. Improved performance at Canadian Regulated Electric Utilities was
driven by overall growth in electrical infrastructure investment combined with
customer growth at FortisAlberta and the higher allowed ROE at FortisBC.
Earnings were lower quarter over quarter at the Terasen Gas companies, mainly as
a result of higher regulator-approved operating expenses and the timing of the
spending of these increased expenses, and at Caribbean Regulated Electric
Utilities, due to lower electricity sales associated with cooler-than-normal
temperatures and poor financial performance at Belize Electricity. Earnings for
the fourth quarter of 2009 were reduced by $5 million related to a provision
taken in the fourth quarter of 2009 for the project cost overrun related to the
conversion of Whistler customer appliances from propane to natural gas but were
favourably impacted by a one-time $3 million corporate tax adjustment at
FortisOntario.
Customer rates have been set, effective January 1, 2011, for the four largest
utilities. The allowed ROE for 2011 at Terasen Gas, FortisBC and FortisAlberta
is 9.5%, 9.9% and an interim 9.0%, respectively, unchanged from each utility's
allowed ROE for 2010. The allowed ROE at FortisAlberta has been declared interim
pending the outcome of a proceeding to review capital structure and finalize the
allowed ROE for 2011, which has commenced. The allowed ROE for 2011 at
Newfoundland Power decreased to 8.38% from 9.0% as a result of the operation of
the ROE automatic adjustment formula.
Standard and Poor's confirmed the Corporation's debt credit rating at A- in
December and DBRS upgraded the Corporation's debt credit rating to A(low) from
BBB(high) in October. The credit ratings reflect the Corporation's low
business-risk profile, reasonable credit metrics, significant reduction in
external debt at Terasen Inc. and the Corporation's demonstrated ability to
acquire and integrate stable utility businesses financed on a conservative
basis.
Cash flow from operating activities was $783 million, up $146 million from $637
million for 2009 due to higher earnings, increased amortization costs collected
through customer rates and favourable working capital changes year over year.
Fortis and its utilities raised $525 million in long-term debt in 2010. In
December Fortis privately placed 10-year US$125 million and 30-year US$75
million notes bearing interest at 3.53% and 5.26%, respectively. Proceeds from
the notes were used to refinance indebtedness under the Corporation's committed
credit facility related to amounts borrowed to repay maturing debt and for
general corporate purposes. In the fourth quarter, FortisAlberta, Terasen Gas
(Vancouver Island) and FortisBC issued unsecured debentures at terms of $125
million 40-year 4.8%, $100 million 30-year 5.2% and $100 million 40-year 5.0%,
respectively. Proceeds from the debentures were mainly used to repay borrowings
under the utilities' committed credit facilities incurred to finance their
capital expenditure programs.
"Fortis utilities are busy building the infrastructure needed to meet our
customers' energy needs. Our capital program is estimated at $1.2 billion for
2011 and near $5.5 billion over the next five years, driven by investment in
infrastructure at our regulated utilities in western Canada and the Waneta
Expansion Project," says Mr. Marshall.
"We will continue to pursue acquisitions of regulated electric and natural gas
utilities in the United States and Canada that will add value for our
shareholders, ever mindful that the priority of Fortis is to meet our obligation
to serve customers," he concludes.
Financial Highlights
For the three and 12 months ended December 31, 2010
Dated February 10, 2011
FORWARD-LOOKING STATEMENT
The following fourth quarter 2010 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, 2009 included in the Corporation's 2009 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 2010 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 2010 media release includes,
but is not limited to, statements regarding: the expected increase in the total
capital cost of the Fraser River South Bank South Arm Rehabilitation Project at
Terasen Gas Inc.; the expected timing of the filing of regulatory applications
and receipt of regulatory decisions; the expected timing of the close of the
sale of the joint-use poles at Newfoundland Power; the expected timing of
receipt of the court decision pertaining to Belize Electricity's June 2008 Final
Decision; the expected total capital cost of FortisAlberta's Automated Meter
Infrastructure Project; the expected deferred replacement energy costs at
Maritime Electric to the end of February 2011;
the expected total capital cost for the construction of the 335-megawatt Waneta
Expansion hydroelectric generating facility and its expected completion date;
expected consolidated gross capital expenditures for 2011 and in total over the
next five years; the expectation that Fortis will become a US Securities and
Exchange Commission Issuer by December 31, 2011 and will adopt US generally
accepted accounting principles effective January 1, 2012; and the expectation
that the Corporation's significant capital program should drive growth in
earnings and dividends. The forecasts and projections that make up the
forward-looking information are based on assumptions which include, but are not
limited to: the receipt of applicable regulatory approvals and requested rate
orders; no significant operational disruptions or environmental liability due to
a catastrophic event or environmental upset caused by severe weather, other acts
of nature or other major event; the continued ability to maintain the gas and
electricity systems to ensure their continued performance; no material capital
project and financing cost overrun related to the construction of the Waneta
Expansion; 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 and foreign exchange rates; no significant variability in
interest rates; no significant counterparty defaults; the continued
competitiveness of natural gas pricing when compared with electricity and other
alternative sources of energy; the continued availability of natural gas supply;
the continued ability to fund defined benefit pension plans; the absence of
significant changes in government energy plans and environmental laws that may
materially affect the operations and cash flows of the Corporation and its
subsidiaries; maintenance of adequate insurance coverage; the ability to obtain
and maintain licences and permits; retention of existing service areas;
maintenance of information technology infrastructure; favourable relations with
First Nations; favourable labour relations; and sufficient human resources to
deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Factors which
could cause results or events to differ from current expectations include, but
are not limited to: regulatory risk; operating and maintenance risks; capital
project budget overruns and financing risk in the Corporation's non-regulated
business; economic conditions; capital resources and liquidity risk; weather and
seasonality; commodity price risk; derivative financial instruments and hedging;
interest rate risk; counterparty risk; competitiveness of natural gas; natural
gas supply; defined benefit pension plan performance and funding requirements;
environmental risks; insurance coverage risk; loss of licences and permits; loss
of service area; changes in the current assumptions and expectations associated
with the transition to new accounting standards; changes in tax legislation;
information technology infrastructure; an ultimate resolution of the
expropriation of the assets of the Exploits River Hydro 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, 2009 and for the three and nine months ended
September 30, 2010, and as otherwise disclosed in this fourth quarter 2010 media
release.
All forward-looking information in this fourth quarter 2010 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 AND FINANCIAL HIGHLIGHTS
Fortis is the largest investor-owned distribution utility in Canada, serving
approximately 2,100,000 gas and electricity customers. Its regulated holdings
include electric utilities in five Canadian provinces and three Caribbean
countries and a natural gas utility in British Columbia, Canada. Fortis owns and
operates non-regulated generation assets across Canada and in Belize and Upper
New York State, and hotels and commercial office and retail space primarily in
Atlantic Canada. In 2010 the Corporation's electricity distribution systems met
a combined peak demand of approximately 5,162 megawatts ("MW") and its gas
distribution system met a peak day demand of 1,421 terajoules ("TJ"). For
additional information on the Corporation's business segments, refer to Note 1
to the Corporation's 2009 annual audited consolidated financial statements.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably to customers at the lowest reasonable cost and conduct business in an
environmentally responsible manner. The Corporation's main business, utility
operations, is highly regulated. It is segmented by franchise area and,
depending on regulatory requirements, by the nature of the assets.
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. Key financial highlights, including
earnings by reportable segment, for the fourth quarters and years ended December
31, 2010 and December 31, 2009 are provided in the following tables.
--------------------------------------------------------------------------
Financial
Highlights
(Unaudited) Quarter Annual
Periods Ended
December 31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue ($
millions) 1,036 1,020 16 3,664 3,643 21
Cash Flow from
Operating
Activities ($
millions) 201 71 130 783 637 146
Net Earnings
Attributable
to Common
Equity
Shareholders
($ millions) 85 81 4 285 262 23
Basic Earnings
per Common
Share ($) 0.49 0.48 0.01 1.65 1.54 0.11
Diluted
Earnings per
Common Share
($) 0.47 0.46 0.01 1.62 1.51 0.11
Weighted
Average
Number of
Common Shares
Outstanding
(millions) 173.9 170.9 3.0 172.9 170.2 2.7
--------------------------------------------------------------------------
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended
December 31 Quarter Annual
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Regulated Gas
Utilities -
Canadian
Terasen Gas
Companies
(1) 45 48 (3) 130 117 13
--------------------------------------------------------------------------
Regulated
Electric
Utilities -
Canadian
Fortis
Alberta 17 15 2 68 60 8
FortisBC (2) 10 8 2 42 37 5
Newfoundland
Power 9 8 1 35 32 3
Other
Canadian
(3) 5 7 (2) 19 20 (1)
--------------------------------------------------------------------------
41 38 3 164 149 15
--------------------------------------------------------------------------
Regulated
Electric
Utilities -
Caribbean (4) 5 7 (2) 23 27 (4)
Non-Regulated
- Fortis
Generation
(5) 5 2 3 20 16 4
Non-Regulated
- Fortis
Properties
(6) 7 5 2 26 24 2
Corporate and
Other (7) (18) (19) 1 (78) (71) (7)
--------------------------------------------------------------------------
Net Earnings
Attributable
to Common
Equity
Shareholders 85 81 4 285 262 23
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island)
Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI")
(2) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant and
Arrow Lakes hydroelectric generating plants and the distribution system
owned by the City of Kelowna. Excludes the non-regulated generation
operations of FortisBC Inc.'s wholly owned partnership, Walden Power
Partnership.
(3) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and, from October 2009,
Algoma Power.
(4) Includes Belize Electricity, in which Fortis holds an approximate 70%
controlling interest; Caribbean Utilities on Grand Cayman, Cayman Islands,
in which Fortis holds an approximate 59% controlling interest; and wholly
owned Fortis Turks and Caicos.
(5) Includes the financial results of non-regulated assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York State,
with a combined generating capacity of 139 megawatts ("MW"), mainly
hydroelectric. Results reflect contribution from the Vaca hydroelectric
generating facility in Belize from March 2010 when the facility was
commissioned. Prior to May 1, 2009, the financial results of Fortis
reflected earnings' contribution associated with the Corporation's 75-MW
water-right entitlement on the Niagara River in Ontario related to the
Rankine hydroelectric generating facility. The water rights expired on
April 30, 2009 at the end of a 100-year term. Additionally, prior to
February 12, 2009, the financial results of the hydroelectric generation
operations in central Newfoundland were consolidated in the financial
statements of Fortis. Effective February 12, 2009, the Corporation
discontinued the consolidation method of accounting for the generation
operations in central Newfoundland due to the Corporation no longer having
control over the operations and cash flows, as a result of the
expropriation of the assets of the Exploits River Hydro Partnership by the
Government of Newfoundland and Labrador. For a further discussion of this
matter, refer to the "Critical Accounting Estimates - Contingencies"
section of the MD&A for the year ended December 31, 2009.
(6) Fortis Properties owns and operates 21 hotels, comprised of more than
4,100 rooms, in eight Canadian provinces and approximately 2.7 million
square feet of commercial office and retail space primarily in Atlantic
Canada.
(7) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. ("Terasen") corporate-related activities and the financial
results of Terasen's 30% ownership interest in CustomerWorks Limited
Partnership ("CWLP") and of Terasen's non-regulated wholly owned
subsidiary Terasen Energy Services Inc. ("TES")
SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
TERASEN GAS COMPANIES
--------------------------------------------------------------------------
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended
December 31 Quarter Annual
(TJ) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Core -
Residential and
Commercial 37,035 42,701 (5,666) 113,635 125,238 (11,603)
Industrial 1,551 1,659 (108) 5,259 6,038 (779)
--------------------------------------------------------------------------
Total Sales
Volumes 38,586 44,360 (5,774) 118,894 131,276 (12,382)
Transportation
Volumes 18,405 16,937 1,468 60,363 60,067 296
Throughput under
Fixed Revenue
Contracts 3,407 3,703 (296) 13,765 15,887 (2,122)
--------------------------------------------------------------------------
Total Gas Volumes 60,398 65,000 (4,602) 193,022 207,230 (14,208)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Gas Volumes Variance
Quarter over Quarter
Unfavourable
-- Lower average gas consumption by residential and commercial customers,
as a result of warmer temperatures
Favourable
-- Higher transportation volumes, as a result of the favourable impact of
continued improving economic conditions in the forestry sector,
including a pulp and paper mill customer returning to service
Factors Contributing to Gas Volumes Variance
Year over Year
Unfavourable
-- Lower average gas consumption by residential, commercial and
industrial customers, as a result of warmer average temperatures in
2010 compared to 2009
-- Lower volumes under fixed revenue contracts, mainly due to reduced
demand from a large customer resulting from changing their gas supply
requirements from peak demand to emergency demand
Net customer additions were approximately 9,400 for 2010 compared to 8,200 for
2009. Customer additions increased year over year due to increased building
activity.
The Terasen Gas companies earn approximately the same margin regardless of
whether a customer contracts for the purchase and delivery of natural gas or for
the transportation only of natural gas.
As a result of the operation of regulator-approved deferral mechanisms, changes
in consumption levels and energy supply costs from those forecast to set
customer gas rates do not materially affect earnings.
Due to natural gas consumption patterns, earnings at the Terasen Gas companies
are highest in the first and fourth quarters. As a result of seasonality,
interim earnings are not indicative of annual earnings.
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
December 31 Quarter Annual
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 480 497 (17) 1,547 1,663 (116)
Energy Supply Costs 277 300 (23) 863 1,022 (159)
Operating Expenses 87 79 8 288 268 20
Amortization 27 26 1 108 102 6
Finance Charges 29 30 (1) 113 121 (8)
Corporate Taxes 15 14 1 45 33 12
--------------------------------------------------------------------------
Earnings 45 48 (3) 130 117 13
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Revenue Variance
Quarter over Quarter
Unfavourable
-- Lower average gas consumption by residential and commercial customers
-- Lower commodity cost of natural gas charged to customers
Favourable
-- The increase in customer delivery rates, effective January 1, 2010,
relating to the increase in the deemed common equity component of the
total capital structure ("equity component") for Terasen Gas Inc.
("TGI") to 40% from 35% and increased regulator-approved operating
expenses and amortization costs recoverable from customers
Factors Contributing to Revenue Variance
Year over Year
Unfavourable
-- The same factors as for the quarter discussed above
Favourable
-- The increase in customer delivery rates, effective January 1, 2010,
which mainly reflected: (i) the impact of the increase in the allowed
rate of return on common shareholders' equity ("ROE") to 9.50% from
8.47% for TGI and to 10.00% for Terasen Gas (Vancouver Island) Inc.
("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI") from 9.17% and
8.97%, respectively, for a full year in 2010 compared to half a year
in 2009; (ii) the increase in the equity component for TGI to 40% from
35%, effective January 1, 2010; and (iii) higher regulator-approved
operating expenses and amortization costs recoverable from customers.
The increase in the allowed ROEs for the Terasen Gas companies was
effective July 1, 2009.
Factors Contributing to Earnings Variance
Quarter over Quarter
Unfavourable
-- Higher operating expenses due to the timing of the expenses during
2010, with a higher weighting in the fourth quarter of 2010, combined
with: (i) increased labour and employee-benefit costs; (ii) new
initiatives agreed to in the regulator-approved Negotiated Settlement
Agreement ("NSA") related to 2010 and 2011 revenue requirements
resulting in higher planned maintenance and operating activities in
2010 compared to 2009; (iii) the expensing of asset removal costs to
operating expenses, effective January 1, 2010, as a result of the NSA;
and (iv) lower capitalized overhead costs, due to a reduction in the
capitalization rate, also as a result of the NSA. The asset removal
costs and higher expensed overhead costs were approved for collection
in customer delivery rates. Prior to 2010, asset removal costs were
recorded against accumulated amortization.
-- Increased amortization costs due to higher amortization rates and
continued investment in utility capital assets. Amortization rates for
2010 were determined and approved by the regulator upon review of a
recent depreciation study. The increase in amortization costs is being
collected in customer delivery rates.
-- Higher effective corporate income taxes, mainly due to higher non-
deductible expenses in 2010 compared to 2009, partially offset by a
lower statutory income tax rate
Favourable
-- The increase in customer delivery rates, effective January 1, 2010, as
discussed above for the quarterly revenue variance
-- The expensing of a provision taken in the fourth quarter of 2009 of
approximately $6 million ($5 million after tax) of the project cost
overrun related to the conversion of Whistler customer appliances from
propane to natural gas
-- Lower finance charges, due to lower average credit facility borrowings
Factors Contributing to Earnings Variance
Year over Year
Favourable
-- The increase in customer delivery rates, effective January 1, 2010, as
discussed above for the annual revenue variance
-- Lower finance charges, for the same reason as for the quarter
discussed above
-- The favourable $9 million impact of the regulator-approved reversal in
the third quarter of 2010 of most of the project cost overrun ($5
million pre-tax, $4 million after tax) related to the conversion of
Whistler customer appliances, which was previously provided for and
expensed in the fourth quarter of 2009 ($6 million pre-tax, $5 million
after tax)
Unfavourable
-- Increased operating expenses, amortization costs and higher effective
corporate income taxes for the same reasons as for the quarter
discussed above
In December 2010 TGVI issued 30-year $100 million 5.20% unsecured debentures,
the net proceeds of which were used to repay committed credit facility
borrowings incurred in support of the utility's capital expenditure program.
For an update on material regulatory decisions and applications pertaining to
the Terasen Gas companies for the fourth quarter of 2010, refer to the
"Regulatory Highlights" section of this fourth quarter 2010 media release.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December
31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Deliveries
(gigawatt hours
("GWh")) 4,255 4,129 126 15,866 15,865 1
--------------------------------------------------------------------------
($ millions)
Revenue 99 86 13 388 331 57
Operating Expenses 37 34 3 141 132 9
Amortization 32 24 8 126 94 32
Finance Charges 14 14 - 54 50 4
Corporate Tax Recovery (1) (1) - (1) (5) 4
--------------------------------------------------------------------------
Earnings 17 15 2 68 60 8
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Energy Deliveries Variance
Quarter over Quarter
Favourable
-- Higher energy deliveries to commercial and oil and gas customers, due
to increased oil and gas activities and an increase in the number of
customers
Unfavourable
-- Decreased energy deliveries to farm and irrigation, and residential
customers, mainly due to lower average consumption resulting from
relatively milder temperatures and increased rainfall, partially offset
by the impact of an increase in the number of customers
Factors Contributing to Energy Deliveries Variance
Year over Year
Favourable
-- Higher energy deliveries to residential, commercial and oil and gas
customers, mainly associated with an increase in the number of customers
Unfavourable
-- Decreased energy deliveries to farm and irrigation customers, mainly
due to lower average consumption resulting from relatively milder
temperatures and increased rainfall, partially offset by an increase
in the number of customers
-- Decreased energy deliveries to other industrial customers, mainly due
to lower average consumption resulting from the impact of unfavourable
economic conditions, and a reduction in the number of customers
The total number of customers at FortisAlberta increased approximately 11,000
from 2009, reaching approximately 491,000 as at December 31, 2010.
As a significant portion of FortisAlberta's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue. Revenues are a
function of numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Revenue Variance
Quarter over Quarter and Year over Year
Favourable
-- Accrued electricity rate revenue combined with a 7.5% average increase
in base customer electricity rates, effective January 1, 2010,
associated with the 2010-2011 regulatory rate decision. The customer
rate revenue accrual and rate increase were primarily due to ongoing
investment in electrical infrastructure, and higher regulator-approved
amortization costs, operating expenses and finance charges recoverable
from customers.
-- Customer growth
Unfavourable
-- Electricity rate revenue in the fourth quarter of 2009 reflected the
favourable $3 million retroactive impact, relating to the first three
quarters of 2009, of the increase in the allowed ROE and equity
component, effective January 1, 2009.
-- Lower net transmission revenue of approximately $5 million year over
year. Effective January 1, 2010, as a result of the 2010-2011
regulatory rate decision, all transmission costs and revenue are
deferred to be recovered from, or refunded to, customers in future
rates.
Collection of the rate revenue accrual began with new final customer rates and
riders, effective January 1, 2011, as approved by the regulator.
Factors Contributing to Earnings Variance
Quarter over Quarter and Year over Year
Favourable
-- The increase in electricity distribution rate revenue related to ongoing
investment in electrical infrastructure, customer growth and higher
regulator-approved expenses recoverable from customers.
Unfavourable
-- Increased amortization costs associated with higher overall
amortization rates, as approved in the 2010-2011 regulatory rate
decision, and continued investment in utility capital assets,
partially offset by the impact of the commencement, in 2010, of the
capitalization of amortization for vehicles and tools used in the
construction of other assets, as approved by the regulator
-- Increased operating expenses, mainly due to higher general operating
expenses, higher contracted labour costs for the quarter and higher
internal labour costs for the year
-- Higher finance charges for the year, due to higher debenture
borrowings in support of FortisAlberta's significant capital
expenditure program and the impact of an increase in interest rates on
credit facility borrowings, partially offset by lower average credit
facility borrowings and increased capitalized allowance for funds used
during construction
-- Lower net transmission revenue for the year, for the same reason as
for the revenue variance discussed above
-- Lower corporate tax recoveries for the year, due to lower future
income tax recoveries associated with changes in net customer
deferrals and a favourable adjustment to current income taxes of
approximately $2 million during the second quarter of 2009
-- Electricity rate revenue in the fourth quarter of 2009 reflected the
favourable $3 million retroactive impact, relating to the first three
quarters of 2009, of the increase in the allowed ROE and equity
component, effective January 1, 2009.
In October 2010 FortisAlberta issued 40-year $125 million 4.80% unsecured
debentures, the net proceeds of which were used to repay committed credit
facility borrowings that were incurred primarily to finance capital
expenditures, and for general corporate purposes.
For an update on material regulatory decisions and applications pertaining to
FortisAlberta for the fourth quarter of 2010, refer to the "Regulatory
Highlights" section of this fourth quarter 2010 media release.
FORTISBC
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended
December 31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 847 859 (12) 3,046 3,157 (111)
--------------------------------------------------------------------------
($ millions)
Revenue 73 69 4 266 253 13
Energy Supply Costs 23 22 1 73 72 1
Operating Expenses 21 20 1 73 70 3
Amortization 10 9 1 41 37 4
Finance Charges 8 8 - 32 32 -
Corporate Taxes 1 2 (1) 5 5 -
--------------------------------------------------------------------------
Earnings 10 8 2 42 37 5
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Electricity Sales Variance
Quarter over Quarter and Year over Year
Unfavourable
-- Lower consumption, primarily due to unfavourable weather conditions
Favourable
-- Customer growth
Factors Contributing to Revenue Variance
Quarter over Quarter and Year over Year
Favourable
-- A 6.0% increase in customer electricity rates, effective January 1,
2010, mainly reflecting an increase in the allowed ROE to 9.90% for
2010, up from 8.87% for 2009, and ongoing investment in electrical
infrastructure
-- A 2.9% increase in customer electricity rates, effective September 1,
2010, as a result of the flow through to customers of increased power
purchase costs charged by BC Hydro
-- Increased performance-based rate-setting ("PBR") incentive adjustments
receivable from customers
-- Higher pole attachment revenue for the year
Unfavourable
-- The 1.4% and 3.5% decrease in electricity sales for the quarter and
year, respectively
Factors Contributing to Earnings Variance
Quarter over Quarter
Favourable
-- The increase in customer electricity rates, effective January 1, 2010
-- Increased PBR incentive adjustments
-- Lower effective corporate income taxes, due to higher deductions from
income for income tax purposes compared to accounting purposes in 2010
versus 2009, and a lower statutory income tax rate
Unfavourable
-- Higher energy supply costs associated with the impact of higher
average prices for purchased power
-- Higher operating expenses primarily due to increased labour costs and
general inflationary increases, along with an increase in certain
other operating expenses due to the timing of operating and
maintenance projects in 2010 and their related expenditures
-- Increased amortization costs associated with continued investment in
utility capital assets
-- Decreased electricity sales
Factors Contributing to Earnings Variance
Year over Year
Favourable
-- The same factors as for the quarter discussed above
Unfavourable
-- Higher energy supply costs, for the same reason as for the quarter
discussed above
-- Increased water fees and property taxes, and higher operating and
maintenance costs due to increased labour costs and general
inflationary increases, partially offset by an increase in capitalized
overhead costs
-- Increased amortization costs, for the same reason as for the quarter
discussed above
-- Decreased electricity sales
-- Lower earnings' contribution from non-regulated operating, maintenance
and management services, primarily due to higher operating costs
In November 2010 FortisBC issued 40-year $100 million 5.00% unsecured
debentures, the net proceeds of which were used to repay committed credit
facility borrowings and finance capital expenditures and working capital
requirements.
For an update on material regulatory decisions and applications pertaining to
FortisBC for the fourth quarter of 2010, refer to the "Regulatory Highlights"
section of this fourth quarter 2010 media release.
NEWFOUNDLAND POWER
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended December
31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 1,488 1,474 14 5,419 5,299 120
--------------------------------------------------------------------------
($ millions)
Revenue 152 146 6 555 527 28
Energy Supply Costs 102 99 3 358 346 12
Operating Expenses 15 13 2 62 52 10
Amortization 12 12 - 47 45 2
Finance Charges 9 9 - 36 35 1
Corporate Taxes 4 4 - 16 16 -
--------------------------------------------------------------------------
10 9 1 36 33 3
Non-Controlling
Interests 1 1 - 1 1 -
--------------------------------------------------------------------------
Earnings 9 8 1 35 32 3
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Electricity Sales Variance
Quarter over Quarter
Favourable
-- Customer growth
Unfavourable
-- Lower average consumption mainly due to milder temperatures and lower
activity in the commercial sector
Factors Contributing to Electricity Sales Variance
Year over Year
Favourable
-- Customer growth and higher average consumption
Factors Contributing to Revenue Variance
Quarter over Quarter and Year over Year
Favourable
-- An average 3.5% increase in customer electricity rates, effective
January 1, 2010, mainly reflecting an increase in the allowed ROE to
9.00% for 2010, up from 8.95% for 2009; ongoing investment in
electrical infrastructure; and higher regulator-approved expenses,
including pension costs, recoverable from customers
-- A 1.0% and 2.3% increase in electricity sales for the quarter and
year, respectively
Factors Contributing to Earnings Variance
Quarter over Quarter
Favourable
-- The average 3.5% increase in customer electricity rates, effective
January 1, 2010
-- Increased electricity sales
-- Lower effective corporate income taxes, due to a reduction in
statutory income tax rates and higher deductions from income for
income tax purposes compared to accounting purposes in 2010 versus
2009
Unfavourable
-- Increased energy supply costs associated with the Company's
hydroelectric generating facilities
-- Higher pension costs and inflationary and wage increases
Factors Contributing to Earnings Variance
Year over Year
Favourable
-- The same factors as for the quarter discussed above
Unfavourable
-- The same factors as for the quarter discussed above
-- Incremental operating costs of approximately $1.5 million incurred in
the third quarter of 2010 as a result of Hurricane Igor, which
impacted over half of the Company's service territory
-- Increased conservation and higher retirement and severance expenses,
partially offset by lower regulatory costs and higher capitalized
overhead costs
-- Increased amortization costs associated with continued investment in
utility capital assets
-- Higher finance charges associated with interest expense on the $65
million 6.606% bonds issued in May 2009
For an update on material regulatory decisions and applications pertaining to
Newfoundland Power for the fourth quarter of 2010, refer to the "Regulatory
Highlights" section of this fourth quarter 2010 media release.
OTHER CANADIAN ELECTRIC UTILITIES (1)
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended
December 31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Electricity Sales
(GWh) 578 582 (4) 2,328 2,195 133
--------------------------------------------------------------------------
($ millions)
Revenue 87 79 8 331 285 46
Energy Supply Costs 59 50 9 215 183 32
Operating Expenses 12 12 - 45 38 7
Amortization 5 5 - 23 19 4
Finance Charges 5 6 (1) 21 19 2
Corporate Tax
Expense (Recovery) 1 (1) 2 8 6 2
--------------------------------------------------------------------------
Earnings 5 7 (2) 19 20 (1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario includes
financial results of Algoma Power from October 8, 2009, the date of
acquisition.
Factors Contributing to Electricity Sales Variance
Quarter over Quarter
Unfavourable
-- Lower average consumption in Ontario, mainly due to reduced space
heating load as a result of warmer temperatures
Favourable
-- Higher consumption on Prince Edward Island ("PEI") due to residential
customer growth, warmer temperatures favourably impacting crop storage
cooling for the farming sector and increased processing activity in the
commercial sector
Factors Contributing to Electricity Sales Variance
Year over Year
Favourable
-- Higher electricity sales at Algoma Power, mainly due to contribution for
a full year in 2010 compared to three months in 2009. Algoma Power was
acquired by FortisOntario in October 2009.
Factors Contributing to Revenue Variance
Quarter over Quarter
Favourable
-- An average 3.8% increase in customer electricity rates at Algoma
Power, effective December 1, 2010
-- An increase at Maritime Electric, effective August 1, 2010, in the
base amount of energy-related costs being expensed and collected from
customers and recorded in revenue through the basic rate component of
customer billings
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
Unfavourable
-- The 0.7% decrease in electricity sales
Factors Contributing to Revenue Variance
Year over Year
Favourable
-- Higher revenue of approximately $27 million from Algoma Power, mainly
due to a full year of revenue contribution in 2010 compared to three
months in 2009 and the average 3.8% increase in customer electricity
rates at Algoma Power, effective December 1, 2010
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- The increase at Maritime Electric in the base amount of energy-related
costs being collected from customers, for the same reason as for the
quarter discussed above
-- Increases in the base component of customer electricity distribution
rates at Fort Erie, Gananoque and Port Colborne in Ontario, effective
May 1, 2009 and May 1, 2010
Factors Contributing to Earnings Variance
Quarter over Quarter and Year over Year
Unfavourable
-- A one-time favourable adjustment of approximately $3 million to future
income taxes related to prior periods recorded during the fourth quarter
of 2009 at FortisOntario
Favourable
-- Earnings' contribution from Algoma Power increased $0.8 million for
the quarter and $1.3 million for the year. The increase for the
quarter was mainly due to a reduction in operating expenses resulting
from the recognition of capitalized overhead expenses during the
fourth quarter of 2010 relating to the full year. The increase for the
year was primarily due to a full year of earnings' contribution from
Algoma Power in 2010 and the impact of the average 3.8% customer
electricity rate increase at Algoma Power, effective December 1, 2010.
-- Lower finance charges at Maritime Electric, due to lower short-term
borrowing rates and the repayment of a maturing $15 million first
mortgage bond in May 2010 that carried a 12% interest rate
-- Lower effective corporate income taxes at FortisOntario, excluding the
one-time $3 million corporate tax adjustment in the fourth quarter of
2009, due to higher deductions from income for income tax purposes
compared to accounting purposes in 2010 versus 2009
For an update on material regulatory decisions and applications pertaining to
Maritime Electric and FortisOntario for the fourth quarter of 2010, refer to the
"Regulatory Highlights" section of this fourth quarter 2010 media release.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
--------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Annual
Periods Ended
December 31 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.01 1.06 (0.05) 1.03 1.13 (0.10)
Electricity Sales
(GWh) 270 291 (21) 1,150 1,140 10
--------------------------------------------------------------------------
($ millions)
Revenue 84 85 (1) 335 339 (4)
Energy Supply Costs 51 50 1 201 192 9
Operating Expenses 13 13 - 48 54 (6)
Amortization 9 8 1 36 37 (1)
Finance Charges 5 4 1 17 16 1
Corporate Taxes - - - 1 2 (1)
------------------------------------------------------
6 10 (4) 32 38 (6)
Non-Controlling
Interests 1 3 (2) 9 11 (2)
--------------------------------------------------------------------------
Earnings 5 7 (2) 23 27 (4)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00=US$1.00. The reporting
currency of Caribbean Utilities and Fortis Turks and Caicos is the US
dollar.
Factors Contributing to Electricity Sales Variance
Quarter over Quarter
Unfavourable
-- Decreased air conditioning load, as a result of lower average
temperatures experienced on Grand Cayman and in the Turks and Caicos
Islands and Belize
Favourable
-- Customer growth at Belize Electricity
-- Incremental load associated with a new system-connected medical
facility and condominium complex in the Turks and Caicos Islands
Factors Contributing to Electricity Sales Variance
Year over Year
Favourable
-- The same factors as for the quarter discussed above
-- In July 2010 Fortis Turks and Caicos achieved a new record peak load
of 31 MW
Unfavourable
-- Decreased air conditioning load, as a result of lower average
temperatures experienced on Grand Cayman during the second half of
2010
-- Reduced residential customer base at Fortis Turks and Caicos, due to
construction workers leaving the Turks and Caicos Islands
-- Tempered growth due to continuing challenging economic conditions in
the region
Factors Contributing to Revenue Variance
Quarter over Quarter
Unfavourable
-- Approximately $4 million unfavorable foreign exchange associated with
the translation of foreign currency-denominated revenue, due to the
weakening of the US dollar relative to the Canadian dollar
-- An overall 7.2% decrease in electricity sales
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the cost of fuel
Factors Contributing to Revenue Variance
Year over Year
Unfavourable
-- Approximately $33 million associated with unfavourable foreign
currency translation for the same reason as for the quarter discussed
above
-- The unfavourable approximate $1.5 million year-over-year impact of the
reversal of the Court of Appeal judgment at Fortis Turks and Caicos
related to a customer-rate-classification matter
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, for the same reason as for the quarter
discussed above
-- An overall 0.9% increase in electricity sales
-- A 2.4% increase in basic customer electricity rates at Caribbean
Utilities, effective June 1, 2009
Factors Contributing to Earnings Variance
Quarter over Quarter
Unfavourable
-- Higher operating expenses at Belize Electricity, excluding the impact
of foreign exchange, mainly due to increased legal fees associated
with continued regulatory challenges
-- Decreased electricity sales
-- Approximately $0.5 million associated with unfavourable foreign
currency translation
-- Higher amortization costs, excluding the impact of foreign exchange,
mainly due to a change in amortization estimates at Fortis Turks and
Caicos favourably impacting amortization costs by approximately $1.5
million during the fourth quarter of 2009
Factors Contributing to Earnings Variance
Year over Year
Unfavourable
-- Approximately $3 million associated with unfavourable foreign currency
translation
-- Higher operating expenses at Belize Electricity, excluding the impact
of foreign exchange, mainly due to increased legal fees associated
with continued regulatory challenges
-- Higher finance charges, excluding the impact of foreign exchange,
mainly associated with interest expense on the US$40 million 7.5%
unsecured notes issued in May 2009 and July 2009 at Caribbean
Utilities, and lower capitalized allowance for funds used during
construction, combined with higher interest expense on regulatory
liabilities at Belize Electricity
-- Higher amortization costs, excluding the impact of foreign exchange,
mainly associated with continued investment in utility capital assets
-- The favourable impact on energy supply costs in 2009, due to a change
in the methodology for calculating the cost of fuel recoverable from
customers at Fortis Turks and Caicos
-- The unfavourable approximate $1.5 million year-over-year impact of the
reversal of the Court of Appeal judgment at Fortis Turks and Caicos
related to a customer-rate-classification matter
Favourable
-- Excluding the impact of foreign exchange, lower operating expenses at
Caribbean Utilities due to an increased focus on capital projects in
2010 which changed the timing of certain maintenance activities
combined with higher capitalized overhead, and lower operating
expenses at Fortis Turks and Caicos associated with a lower provision
for bad debts
-- Reduced generator maintenance costs at Fortis Turks and Caicos
-- Increased electricity sales
For an update on material regulatory decisions and applications pertaining to
Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos for the
fourth quarter of 2010, refer to the "Regulatory Highlights" section of this
fourth quarter 2010 media release.
NON-REGULATED - FORTIS GENERATION (1)
--------------------------------------------------------------------------
Financial
Highlights
(Unaudited) Quarter Annual
Periods Ended
December 31 2010(2) 2009 Variance 2010(2) 2009 (3) Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Energy Sales
(GWh) 137 87 50 427 583 (156)
--------------------------------------------------------------------------
($ millions)
Revenue 9 5 4 36 39 (3)
Energy Supply
Costs - - - 1 2 (1)
Operating
Expenses 2 2 - 9 11 (2)
Amortization 1 1 - 4 5 (1)
Finance Charges - - - - 2 (2)
Corporate Taxes 1 1 - 2 3 (1)
---------------------------------------------------------
5 1 4 20 16 4
Non-Controlling
Interests - (1) 1 - - -
--------------------------------------------------------------------------
Earnings 5 2 3 20 16 4
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes the results of non-regulated assets in Belize, Ontario,
central Newfoundland, British Columbia and Upper New York State. The
reporting currency for financial results in Belize and Upper New York
State is the US dollar.
(2) Results reflect contribution from the Vaca hydroelectric generating
facility in Belize from March 2010 when the facility was commissioned.
(3) Results reflect contribution from the Rankine hydroelectric generating
facility in Ontario until April 30, 2009, when the Rankine water rights
expired at the end of a 100-year term.
Factors Contributing to Energy Sales Variance
Quarter over Quarter
Favourable
-- Higher rainfall and the commissioning of the Vaca hydroelectric
generating facility in Belize in March 2010. Production by the
facility was 28 GWh for the fourth quarter of 2010.
-- Higher production in Upper New York State, Ontario and British
Columbia, due to higher rainfall
Factors Contributing to Energy Sales Variance
Year over Year
Unfavourable
-- The expiration on April 30, 2009 of the water rights of the Rankine
hydroelectric generating facility in Ontario. Energy sales during 2009
included approximately 215 GWh related to Rankine.
-- Lower energy sales related to central Newfoundland operations. Energy
sales for 2009 included 19 GWh related to central Newfoundland
operations up until February 12, 2009, at which time the consolidation
method of accounting for these operations was discontinued as a
consequence of the actions of the Government of Newfoundland and
Labrador related to expropriation of the assets of the Exploits River
Hydro Partnership (the "Exploits Partnership").
-- Decreased production in Upper New York State, due to lower rainfall
Favourable
-- Higher rainfall and the commissioning of the Vaca hydroelectric
generating facility in Belize in March 2010. Production by the
facility was 83 GWh for 2010.
-- Higher production in British Columbia, due to higher rainfall
Factors Contributing to Revenue Variance
Quarter over Quarter
Favourable
-- Higher production in all operating areas, led by Belize
-- A higher average wholesale market energy sales rate per megawatt hour
("MWh") in Upper New York State, which was US$43.57 for the fourth
quarter of 2010 compared to US$41.18 for the fourth quarter of 2009
-- A higher average energy sales rate per MWh in Ontario, which was
$70.00 for the fourth quarter of 2010 compared to $31.99 for the
fourth quarter of 2009. Effective May 1, 2010, energy produced in
Ontario is being sold under a fixed-price contract. Previously, energy
was sold at market rates.
Factors Contributing to Revenue Variance
Year over Year
Unfavourable
-- The loss of revenue subsequent to the expiration of the Rankine water
rights on April 30, 2009
-- The discontinuance of the consolidation method of accounting for the
financial results of the Exploits Partnership on February 12, 2009
-- Approximately $3 million unfavourable foreign exchange associated with
the translation of US dollar-denominated revenue, due to the weakening
of the US dollar relative to the Canadian dollar
-- Lower production in Upper New York State
Favourable
-- Higher production in Belize and British Columbia
-- A higher average annual wholesale market energy sales rate per MWh in
Upper New York State, which was US$43.12 for 2010 compared to US$38.54
for 2009
-- A higher average annual energy sales rate per MWh in Ontario, which
was $53.17 for 2010 compared to $34.43 for 2009
Factors Contributing to Earnings Variance
Quarter over Quarter
Favourable
-- Higher production in all operating areas, led by Belize
-- Higher average energy sales rates per MWh in Upper New York State and
Ontario
Factors Contributing to Earnings Variance
Year over Year
Favourable
-- Higher production in Belize
-- Reduced finance charges, excluding the impact of foreign exchange, as
a result of higher interest revenue associated with inter-company
lending to regulated operations in Ontario, partially offset by higher
interest expense associated with inter-company lending to finance the
construction of the Vaca hydroelectric generating facility.
Capitalization of interest during the construction period ended with
the commissioning of the facility in 2010.
-- Higher average annual energy sales rates per MWh in Upper New York
State and Ontario, partially offset by lower production in Upper New
York State
Unfavourable
-- The expiration of the Rankine water rights. Earnings' contribution
associated with the Rankine hydroelectric generating facility was
approximately $3.5 million during 2009.
-- Approximately $2 million associated with unfavourable foreign currency
translation
NON-REGULATED - FORTIS PROPERTIES
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
December 31 Quarter Annual
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Hospitality Revenue 40 38 2 160 155 5
Real Estate Revenue 17 16 1 66 64 2
--------------------------------------------------------------------------
Total Revenue 57 54 3 226 219 7
Operating Expenses 38 37 1 151 146 5
Amortization 5 5 - 18 17 1
Finance Charges 6 5 1 24 22 2
Corporate Taxes 1 2 (1) 7 10 (3)
--------------------------------------------------------------------------
Earnings 7 5 2 26 24 2
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Factors Contributing to Revenue Variance
Quarter over Quarter
Favourable
-- Higher revenue contribution from hotel properties in Atlantic Canada
and central Canada
-- A 2.7% increase in revenue per available room ("RevPAR") at the
Hospitality Division to $70.76 for the fourth quarter of 2010 from
$68.87 for the same quarter in 2009. RevPAR increased due to an
overall 2.0% increase in the average room rate and an overall 0.8%
increase in hotel occupancy. Average room rates increased in all
regions, lead by operations in Atlantic Canada. Hotel occupancy at
operations in Atlantic Canada and central Canada increased, while
occupancy at operations in western Canada decreased.
-- Revenue growth in all regions of the Real Estate Division, with the
most significant increase being in Newfoundland, mainly due to rent
increases
Unfavourable
-- A decrease in the occupancy rate at the Real Estate Division to 94.5% as
at December 31, 2010 from 96.2% as at December 31, 2009, mainly
associated with operations in Newfoundland and New Brunswick
Factors Contributing to Revenue Variance
Year over Year
Favourable
-- Revenue contribution from the Holiday Inn Select Windsor, acquired in
April 2009, combined with higher revenue contribution from hotel
properties in Atlantic Canada and central Canada, partially offset by
lower revenue contribution from hotel properties in western Canada
-- A 0.4% increase in RevPAR at the Hospitality Division to $76.83 for
2010 from $76.55 for 2009. RevPAR increased due to an overall 1.8%
increase in the average room rate, partially offset by an overall 1.4%
decrease in hotel occupancy. Average room rates at operations in
western Canada and Atlantic Canada increased. Hotel occupancy at
operations in western Canada decreased, while occupancy at operations
in central Canada and Atlantic Canada increased.
-- Revenue growth in all regions of the Real Estate Division, with the
most significant increases being in Newfoundland and Nova Scotia,
mainly due to rent increases
Unfavourable
-- Decreased occupancy rate at the Real Estate Division, for the same
reason as for the quarter discussed above
Factors Contributing to Earnings Variance
Quarter over Quarter
Favourable
-- Lower effective corporate income taxes associated with lower statutory
income tax rates and their effect of reducing future income tax
liability balances
-- Improved performance at the Real Estate Division, mainly due to rent
increases, and improved performance at hotel operations in Atlantic
Canada and central Canada, driven by increased RevPAR as discussed
above
Unfavourable
-- Lower performance at hotel operations in western Canada, due to the
continued unfavourable impact of the economic downturn on occupancies
in this region
-- Increased finance charges, due to higher debt levels and interest
rates
Factors Contributing to Earnings Variance
Year over Year
Favourable
-- Lower effective corporate income taxes, for the same reason as for the
quarter discussed above
-- Improved performance at the Real Estate Division, for the same reason
as for the quarter discussed above
-- Contribution from the Holiday Inn Select Windsor from April 2009
-- Improved performance at hotel operations in Atlantic Canada, driven by
increased RevPAR as discussed above
Unfavourable
-- The same factors as for the quarter discussed above
CORPORATE AND OTHER (1)
--------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
December 31 Quarter Annual
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 7 6 1 30 27 3
Operating Expenses 3 5 (2) 16 14 2
Amortization 2 1 1 7 8 (1)
Finance Charges (2) 16 20 (4) 73 79 (6)
Corporate Tax
Recovery (3) (6) 3 (16) (21) 5
------------------------------------------------------
(11) (14) 3 (50) (53) 3
Preference Share
Dividends 7 5 2 28 18 10
--------------------------------------------------------------------------
Net Corporate and
Other Expenses (18) (19) 1 (78) (71) (7)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen corporate-related activities and the financial results of
Terasen's 30% ownership interest in CWLP and of Terasen's non-regulated
wholly owned subsidiary TES
(2) Includes dividends on preference shares classified as long-term
liabilities
Factors Contributing to Net Corporate and Other Expenses Variance
Quarter over Quarter
Favourable
-- Lower finance charges, due to the finalization of capitalized
interest, incurred to finance the Vaca hydroelectric generating
facility during the period of construction, and the repayment of
higher interest-bearing debt in 2010. The decrease was partially
offset by the impact of higher average credit facility borrowings. In
October 2010 Fortis redeemed its $100 million 7.4% unsecured
debentures and in April 2010 Terasen redeemed its $125 million 8.0%
Capital Securities with proceeds from borrowings under the
Corporation's committed credit facility.
-- Increased revenue, due to interest income on higher inter-company
lending at higher interest rates to Fortis Properties to finance the
Company's maturing external debt
-- Lower operating expenses associated with differences in the timing of
recovery of operating expenses from subsidiary companies
Unfavourable
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series H in January 2010
Factors Contributing to Net Corporate and Other Expenses Variance
Year over Year
Unfavourable
-- Higher preference share dividends, for the same reason as for the
quarter discussed above
-- Higher operating expenses, primarily due to business development costs
incurred in 2010, partially offset by higher recovery of costs from
subsidiary companies and lower non-regulated operating expenses at
Terasen Energy Services Inc.
Favourable
-- Lower finance charges, excluding the impact of foreign exchange, for
the same reasons as for the quarter discussed above. The decrease was
partially offset by interest expense on the 30-year $200 million 6.51%
unsecured debentures issued in July 2009 and the impact of higher
average credit facility borrowings
-- A favourable foreign exchange impact of approximately $2.5 million
associated with the translation of US dollar-denominated interest
expense, due to the weakening of the US dollar relative to the
Canadian dollar
-- Increased revenue, for the same reason as for the quarter discussed
above
In December 2010 Fortis issued 10-year US$125 million 3.53% and 30-year US$75
million 5.26% unsecured notes. The net proceeds of the private note offerings
were used to repay committed credit facility borrowings that were incurred to
repay the Corporation's $100 million 7.4% unsecured debentures that matured in
October 2010 and for general corporate purposes.
REGULATORY HIGHLIGHTS
The following is an update on material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the fourth quarter of 2010:
Material Regulatory Decisions and Applications
--------------------------------------------------------------------------
Regulated Utility Summary Description
--------------------------------------------------------------------------
TGI/TGVI/TGWI - TGI and TGVI review with the British Columbia
Utilities Commission ("BCUC") natural gas and
propane commodity rates and mid-stream rates every
three months in order to ensure the flow-through
rates charged to customers are sufficient to cover
the cost of purchasing natural gas and propane and
contracting for mid-stream resources, such as
third-party pipeline or storage capacity. The
commodity cost of natural gas and propane and mid-
stream costs are flowed through to customers
without markup. In December 2010 TGI filed an
application with the BCUC to provide fuelling
services through TGI-owned and operated compressed
natural gas and liquefied natural gas ("LNG")
fuelling stations. If the application is approved,
commercial customers will be able to safely and
economically refuel their fleet vehicles on their
own premises, at rates regulated by the BCUC,
using stations provided by TGI.
- In December 2010 TGI received approval from the
BCUC for a new renewable natural gas program for
an initial two-year period. In 2011 up to 24,000
residential customers will be able to subscribe to
the program, paying an approximate $4 monthly
premium to replace 10% of their natural gas supply
with biomethane. The BCUC approval also allows TGI
to implement agreements with Catalyst Power Inc.
and the Columbia Shuswap Regional District to
collect biogas from agricultural waste and a
landfill site, respectively.
- In December 2010 the Terasen Gas companies filed
a report with the BCUC, as required, which
included a study by an external consultant,
engaged by the utilities, of alternative formulaic
ROE automatic adjustment mechanisms used in North
America. Based on the study, the Terasen Gas
companies are not proposing to adopt a formulaic
ROE automatic adjustment mechanism at this time.
- TGI, TGVI and TGWI are considering an
amalgamation of the three companies. An
amalgamation would require an application to be
approved by the BCUC and consent of the Government
of British Columbia. While a decision to proceed
with an amalgamation has not yet been made, the
Terasen Gas companies are contemplating bringing
forth an application during 2011.
- In January 2011 TGI filed its review of the
Price Risk Management Plan ("PRMP") objectives
with the BCUC related to its gas commodity hedging
plan and also submitted a 2011-2014 PRMP. An
updated PRMP for TGVI is expected to be filed by
April 2011.
--------------------------------------------------------------------------
FortisBC - In November 2010 FortisBC received Board of
Directors' approval to enter into the Waneta
Expansion Capacity Agreement to purchase capacity
output from the 335-MW Waneta Expansion
hydroelectric generating facility. The Waneta
Expansion Capacity Agreement, which was accepted
by the BCUC in September 2010, will allow FortisBC
to purchase capacity for 40 years upon completion
of the Waneta Expansion, which is anticipated in
spring 2015. For further information, refer to the
"Capital Program" section of this media release.
- In December 2010 the BCUC approved an NSA
pertaining to FortisBC's 2011 Revenue Requirements
Application. The result was a general customer
electricity rate increase of 6.6%, effective
January 1, 2011. The rate increase was primarily
the result of the Company's ongoing investment in
electrical infrastructure and the higher cost of
capital. Customer rates for 2011 reflect an
allowed ROE of 9.90%, unchanged from 2010.
- In December 2010 FortisBC received BCUC approval
of its 2011 Capital Expenditure Plan. Forecast
capital expenditures for 2011 total approximately
$99 million.
--------------------------------------------------------------------------
FortisAlberta - In October 2010 the Central Alberta Rural
Electrification Association ("CAREA") filed an
application with the Alberta Utilities Commission
("AUC") requesting that CAREA be entitled to serve
any new customer in the overlapping CAREA service
area wishing to obtain electricity for use on
property, and that FortisAlberta be restricted to,
and shall provide, electricity distribution
service in CAREA's service area only to a customer
in that service area who is not being provided
service by CAREA. FortisAlberta has intervened in
the proceeding.
- In December 2010 the AUC issued its decision on
FortisAlberta's August 2010 Compliance Filing,
which incorporated the AUC's decision, received in
July 2010, on the Company's 2010 and 2011
Distribution Tariff Application ("DTA"). The
December 2010 decision approved the Company's
distribution revenue requirements of $346 million
for 2010 and $368 million for 2011. New final
distribution electricity rates and rate riders
were also approved, effective January 1, 2011.
- In its 2010 and 2011 DTA, FortisAlberta had
requested an update in the forecast capital cost
of its Automated Meter Infrastructure ("AMI")
Project, bringing the total forecast project cost
to $126 million (excluding the $15 million cost of
the pilot program), up from an original total
forecast project cost of $104 million. The AUC
reached the conclusion, however, that the capital
cost of the AMI Project of $104 million (excluding
the pilot program) had formed part of the
Company's 2008 and 2009 NSA that had been approved
in 2008 and, therefore, did not approve the
updated forecast. The Company filed a Review and
Variance Application with the AUC and a Leave to
Appeal with the Alberta Court of Appeal regarding
this conclusion. The AUC issued its decision
regarding the Review and Variance Application
approving a hearing into the prudency of the
capital expenditures above $104 million. A
proceeding has been initiated and will be in
writing with a decision expected in the second
quarter of 2011. The Company's Leave to Appeal
has been adjourned pending the determination of
the Review and Variance. The Utilities Consumer
Advocate filed with the Alberta Court of Appeal a
Leave to Appeal request which has similarly been
adjourned.
- The AUC issued a Notice of Commission-Initiated
Proceeding in December 2010 to finalize the
allowed ROE for 2011, review capital structure and
consider whether a return to a formula-based
approach for annually setting the allowed ROE,
beginning in 2012, is warranted. In the absence
of a formula-based approach, the AUC is expected
to consider how the allowed ROE will be set for
2012. This proceeding will also consider
additional matters associated with customer
contributions.
- The AUC has initiated a process to reform
utility rate regulation in Alberta. The AUC has
expressed its intention to apply a PBR formula to
distribution service electricity rates.
FortisAlberta is currently assessing PBR and will
participate fully in the AUC process. The Company
will submit a 2012 and 2013 Cost of Service
("COS") Application in the first quarter of 2011
under the Uniform System of Accounts/Minimum
Filing Requirements format in order to bridge the
transition between COS and possible PBR
regulation.
--------------------------------------------------------------------------
Newfoundland Power - In November 2010 the Newfoundland and Labrador
Board of Commissioners of Public Utilities ("PUB")
approved Newfoundland Power's application to defer
the recovery of expected increased costs of $2.4
million, due to expiring regulatory amortizations,
in 2011.
- In November 2010 the PUB approved Newfoundland
Power's 2011 Capital Budget Plan totaling
approximately $73 million, before customer
contributions.
- In accordance with the operation of the ROE
automatic adjustment formula, Newfoundland Power's
allowed ROE has been reduced from 9.00% for 2010
to 8.38% for 2011.
- In December 2010 the PUB approved Newfoundland
Power's application to: (i) adopt the accrual
method of accounting for other post-employment
benefit ("OPEB") costs, effective January 1, 2011;
(ii) recover the transitional regulatory asset
balance of approximately $53 million, associated
with adoption of accrual accounting, over a 15-
year period; and (iii) adopt an OPEB cost-variance
deferral account to capture differences between
OPEB expense calculated in accordance with
Canadian GAAP and OPEB expense approved by the PUB
for rate-setting purposes.
- In December 2010 Newfoundland Power received
approval from the PUB for an overall average 0.8%
increase in customer electricity rates, effective
January 1, 2011, resulting from the PUB's approval
for the Company to change its accounting practices
for OPEB costs, as described above, partially
offset by the impact of the decrease in the
allowed ROE for 2011.
- In December 2010 Newfoundland Power and Bell
Aliant signed a new Support Structure Agreement,
effective January 1, 2011, whereby Bell Aliant
will buy back 40% of all joint-use poles and
related infrastructure owned by Newfoundland Power
for approximately $46 million. This transaction
represents approximately 5% of Newfoundland
Power's rate base. In 2001 Newfoundland Power
purchased joint-use poles and related
infrastructure from Bell Aliant (formerly Aliant
Telecom Inc.) under a 10-year Joint-Use Facilities
Partnership Agreement ("JUFPA") that expired
December 31, 2010. Bell Aliant has 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. Bell Aliant
exercised the option to buy back these poles from
Newfoundland Power. The Support Structure
Agreement is subject to certain conditions,
including PUB approval of the sale of 40% of the
Company's joint-use poles, which must be met by
both parties by June 30, 2011, or either party may
choose to terminate. In the event of termination,
the rights and recourses under the JUFPA will
remain in effect for both parties. Newfoundland
Power has filed an application with the PUB
requesting approval of the transaction and expects
the transaction to close in 2011.
- As at December 31, 2010 Newfoundland Power
recorded assets held for sale in the amount of
approximately $45 million, which represented the
estimated sales price less cost to sell the joint-
use poles. The estimated sales price will be
adjusted upon completion of a pole survey in 2011.
Effective January 1, 2011, the Company will no
longer be receiving pole rental revenue from Bell
Aliant. However, Newfoundland Power will be
responsible for the construction and maintenance
of Bell Aliant's support structure requirements
throughout 2011. The Support Structure Agreement
with Bell Aliant is not expected to materially
impact Newfoundland Power's ability to earn a
reasonable rate of return on its rate base in
2011. Newfoundland Power is currently working with
Bell Aliant regarding the future operational and
financial aspects of this transaction beyond 2011.
The Company anticipates the proceeds from this
transaction will be used to pay down its credit
facility borrowings and maintain its equity
component at 45%.
- The Company is currently assessing the
requirement for it to file an application with the
PUB to recover expected increased costs in 2012.
--------------------------------------------------------------------------
Maritime Electric - In November 2010 Maritime Electric entered into
a power purchase agreement with New Brunswick
Power ("NB Power") for a five-year period
commencing March 2011, which will result in lower
and stable power purchase costs for customers over
the period.
- In November 2010 Maritime Electric signed the
Prince Edward Island 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 will assume responsibility for
the cost of replacement energy and the monthly
operating and maintenance costs related to the NB
Power Point Lepreau Nuclear Generating Station
("Point Lepreau"), effective March 1, 2011 until
Point Lepreau is fully refurbished, which is
expected in fall 2012. The Government of PEI will
finance these costs, which are expected to be
recovered from customers over a 25-year period
beginning when Point Lepreau returns to service.
In the event that Point Lepreau does not return to
service by fall 2012, the Government of PEI
reserves the right to cease the monthly payments.
As permitted by the Island Regulatory and Appeals
Commission, replacement energy costs incurred
during the refurbishment period are being deferred
by Maritime Electric and are expected to total
approximately $47 million to the end of February
2011. The nature and timing of the recovery of
the deferred costs is subject to further review by
a commission to be established by the Government
of PEI. The Accord also provides for the
financing by the Government of PEI of costs
associated with Maritime Electric's termination of
the Dalhousie Unit Participation Agreement. The
costs will be subsequently collected from
customers over a period to be established by the
Government of PEI. As a result of the Accord,
customer electricity rates will decrease by
approximately 14.0% effective March 1, 2011, at
which time there will commence a two-year customer
rate freeze.
- In December 2010 Maritime Electric received
regulatory approval, as filed, of its 2011 Capital
Budget totaling approximately $23 million, before
customer contributions.
--------------------------------------------------------------------------
FortisOntario - In November 2010 FortisOntario filed Third-
Generation Incentive Rate Mechanism ("IRM")
electricity distribution rate applications for
Fort Erie, Gananoque and Port Colborne for
customer rates effective May 1, 2011. The Ontario
Energy Board ("OEB") will publish the applicable
inflationary productivity factors in the first
quarter of 2011. Customer electricity rates for
2011 will reflect an allowed ROE of 8.01% on a
deemed equity component of 40%.
- FortisOntario intends to file a COS Application
in April 2011 for harmonized electricity
distribution rates in Fort Erie, Port Colborne and
Gananoque, effective January 1, 2012, using a 2012
forward test year.
- In November 2010 the OEB approved an NSA
pertaining to Algoma Power's electricity
distribution rate application for customer rates,
effective December 1, 2010 through December 31,
2011, using a 2011 forward test year. The rates
reflect an approved allowed ROE of 9.85% on a
deemed equity component of 40%. The OEB approval
resulted in a 2011 revenue requirement of $20
million, of which approximately $11 million will
be recovered through the Rural and Remote Rate
Protection ("RRRP") Program with the remainder to
be recovered through increased customer rates and
charges. Through regulations relating to the RRRP
Program, the average increase in the electricity
delivery charge to customers, effective December
1, 2010, was 2.5%. The overall impact of the OEB
rate decision on an average customer's electricity
bill was an increase of 3.8%, including rate
riders and other charges.
- The present form of Third-Generation IRM will
not accommodate Algoma Power's customer rate
structure and the RRRP Program; therefore, Algoma
Power has agreed to consult with interveners to
develop a form of incentive rate-making that may
be used between rebasing periods. Due to
regulations in Ontario associated with the RRRP
Program, customer electricity distribution rates
at Algoma Power are tied to the average changes in
rates of other electric utilities in Ontario.
Pending these consultations, Algoma Power will
file for incentive rate-making for customer
electricity distribution rates, effective January
1, 2012.
--------------------------------------------------------------------------
Belize Electricity - The evidentiary portion of the trial of Belize
Electricity's appeal of the PUC's June 2008 Final
Decision was heard in October 2010 with closing
arguments completed in December 2010. A court
decision on the matter is expected in the first
quarter of 2011.
--------------------------------------------------------------------------
Caribbean Utilities - In November 2010 Caribbean Utilities filed its
2011-2015 Capital Investment Plan ("CIP") totaling
approximately US$219 million. The 2011-2015 CIP
was prepared upon the basis of the Company's
application to the Electricity Regulatory
Authority ("ERA") for a delay in any new
generation installation until there is more
certainty in growth forecasts. In January 2011
the ERA provided general approval of the US$134
million of proposed non-generation installation
expenditures in the CIP. The remaining US$85
million of the CIP related to new generation
installation, which would be subject to a
competitive solicitation process. The general
approval of non-generation expenditures is subject
to Caribbean Utilities providing additional
information related to certain planned projects.
Final approval of the CIP is expected during the
first quarter of 2011.
--------------------------------------------------------------------------
Fortis Turks and Caicos - In September 2010 Fortis Turks and Caicos
received draft proposals and terms of reference
from the Governor of the Turks and Caicos Islands
(the "Governor") to review the Company's
Electricity Rate Review filing. Management has
acknowledged the Governor's proposed terms of
reference and objectives, and has proposed that a
jointly funded and identified outside independent
consultant be engaged to conduct a review of the
filing and current rate-setting mechanism and make
recommendations regarding both.
--------------------------------------------------------------------------
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to allow the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. To help ensure access to capital, the Corporation targets a
consolidated long-term capital structure containing approximately 40% equity,
including preference shares, and 60% debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own capital
structure in line with the deemed capital structure reflected in the utility's
customer rates.
The consolidated capital structure of Fortis is presented in the following table.
--------------------------------------------------------------------------
Capital Structure
(Unaudited) As at December 31
2010 2009
($ millions) (%)($ millions) (%)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total debt and capital
lease obligations (net of
cash) (1) 5,914 58.4 5,830 60.2
Preference shares (2) 912 9.0 667 6.9
Common shareholders'
equity 3,305 32.6 3,193 32.9
--------------------------------------------------------------------------
Total (3) 10,131 100.0 9,690 100.0
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity
(3) Excludes amounts related to non-controlling interests
The change in the capital structure was driven by the issuance of $250 million
preference shares in January 2010, and increased common shares outstanding
reflecting the impact of the Corporation's dividend reinvestment and share
purchase plans. Repayments of long-term debt, capital lease obligations and
short-term borrowings during 2010 were partially offset by proceeds from the
issuance of long-term debt and the preference shares.
Credit Ratings: The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A-(stable) (long-term corporate and
unsecured debt credit rating)
DBRS A(low) (unsecured debt credit rating)
In December 2010 S&P confirmed the Corporation's long-term corporate and
unsecured debt credit rating of A-(stable) and in October 2010 DBRS upgraded the
Corporation's unsecured debt credit rating to A(low) from BBB(high). The credit
ratings reflect the Corporation's low business-risk profile and diversity of its
operations, the stand-alone nature and financial separation of each of the
regulated subsidiaries of Fortis, management's commitment to maintaining low
levels of debt at the holding company level and the significant reduction in
external debt at Terasen, the Corporation's reasonable credit metrics, and the
Corporation's demonstrated ability and continued focus of acquiring and
integrating stable regulated utility businesses financed on a conservative
basis.
CASH FLOW
Summary of Consolidated Cash Flows: The table below outlines the Corporation's
consolidated sources and uses of cash for the three and 12 months ended December
31, 2010, as compared to the same periods in 2009, followed by a discussion of
the nature of the variances in cash flows.
--------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended
December 31 Quarter Annual
($ millions) 2010 2009 Variance 2010 2009 Variance
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Cash, Beginning of
Period 64 106 (42) 85 66 19
Cash Provided by
(Used in):
Operating
Activities 201 71 130 783 637 146
Investing
Activities (333) (312) (21) (991) (1,045) 54
Financing
Activities 177 221 (44) 232 431 (199)
Effect of Exchange
Rate Changes on
Cash and Cash
Equivalents - (1) 1 - (4) 4
--------------------------------------------------------------------------
Cash, End of Period 109 85 24 109 85 24
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $130 million higher quarter over quarter. The increase
was mainly due to: (i) higher earnings; (ii) the collection from customers of
increased amortization costs, mainly at the Terasen Gas companies, as approved
by the regulators; (iii) favourable working capital changes at the Terasen Gas
companies, reflecting differences in the commodity cost of natural gas and the
cost of natural gas charged to customers quarter over quarter and the effects of
seasonality; (iv) favourable changes in the Alberta Electric System Operator
("AESO") charges deferral account at FortisAlberta; and (v) the timing of the
declaration of common share dividends for the first quarter of 2010.
Annual cash flow from operating activities, after working capital adjustments,
was $146 million higher than the previous year. The increase was driven by: (i)
higher earnings; (ii) the collection from customers of increased amortization
costs, mainly at the Terasen Gas companies, as approved by the regulators; (iii)
favourable changes in the AESO charges deferral account at FortisAlberta; (iv) a
decrease in the amount of corporate taxes paid at Newfoundland Power; and (v)
the timing of the declaration of common share dividends for the first quarter of
2010. The increase was partially offset by unfavourable working capital changes
at the Terasen Gas companies, due to differences in the commodity cost of
natural gas and the cost of natural gas charged to customers year over year and
the effects of seasonality.
Investing Activities: Cash used in investing activities was $21 million higher
quarter over quarter, driven by higher gross capital expenditures due to the
commencement of construction of the non-regulated Waneta Expansion late in 2010
and increased capital spending at FortisAlberta, partially offset by the
acquisition of Algoma Power during the fourth quarter of 2009, higher proceeds
from the sale of utility capital assets and higher contributions in aid of
construction.
Annual cash used in investing activities was $54 million lower than the previous
year. The decrease related to higher proceeds from the sale of utility capital
assets, increased contributions in aid of construction and the acquisition of
Algoma Power and the Holiday Inn Select Windsor in 2009. The decrease was
partially offset by higher gross capital expenditures related to the
commencement of construction of the non-regulated Waneta Expansion late in 2010
and higher capital spending at FortisBC, partially offset by lower capital
spending at FortisAlberta and at Caribbean Regulated Electric Utilities.
Financing Activities: Cash provided by financing activities was $44 million
lower quarter over quarter, primarily due to the timing of the declaration of
common share dividends for the first quarter of 2010 and a lower net increase in
debt, partially offset by higher advances from non-controlling interests and
higher proceeds from the issuance of common shares.
Annual cash provided by financing activities was $199 million lower than the
previous year. The decrease was due to the timing of the declaration of common
share dividends for the first quarter of 2010, increased dividends per common
share and a lower net increase in debt, partially offset by higher proceeds from
the issuance of preference and common shares and higher advances from
non-controlling interests. In January 2010 Fortis publicly issued $250 million
Five-Year Fixed Rate Reset First Preference Shares, Series H.
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.
Gross consolidated capital expenditures for the year ended December 31, 2010
were $1,073 million. A breakdown of gross consolidated capital expenditures by
segment for 2010 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year Ended December 31, 2010
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Elec- Regu- Elec-
tric lated tric Non-
Terasen New- Utili- Utili- Utili- Regu-
Gas Fortis found- ties - ties - ties - lated - Fortis
Compa- Alberta Fortis land Cana- Cana- Cari- Utility Proper-
nies (2) BC Power dian dian bbean (3) ties Total
----------------------------------------------------------------------------
253 379 139 78 48 897 72 85 19 1,073
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital
assets, income producing properties and intangible assets, as reflected in
the consolidated statement of cash flows. Includes asset removal and site
restoration expenditures, net of salvage proceeds, for those utilities
where such expenditures are permissible in rate base in 2010. Excludes
capitalized amortization and non-cash equity component of the allowance
for funds used during construction.
(2) Includes payments made to AESO for investment in transmission capital
projects
(3) Includes non-regulated generation and corporate capital expenditures
Gross consolidated capital expenditures of $1,073 million for 2010 were $25
million lower than $1,098 million forecast for 2010 as disclosed in the MD&A for
the year ended December 31, 2009. Planned capital expenditures are based on
detailed forecasts of energy demand, weather, cost of labour and materials, as
well as other factors, including economic conditions, which could change and
cause actual expenditures to differ from forecasts. A decrease in capital
spending at the Terasen Gas companies largely due to: (i) a regulator-approved
decrease in capitalized overhead costs; (ii) a shift in capital spending from
2010 to 2011 related to certain projects; and (iii) lower-than-forecast capital
spending on alternative energy projects, combined with lower actual capital
costs at FortisBC mainly due to prevailing market conditions coupled with a
shift in capital spending from 2010 to 2011 for certain projects, was partially
offset by increased capital spending at the Non-Regulated Generation segment
associated with the commencement of construction of the non-regulated Waneta
Expansion late in 2010.
An update on significant capital projects for 2010 from that disclosed in the
MD&A as at December 31, 2009 is provided below.
During 2010 TGI's Fraser River South Bank South Arm Rehabilitation Project
experienced difficulties with one of the directional drills and the project is
expected to be in service in 2011, rather than in 2010 as originally expected.
The project is expected to cost approximately $35 million, up from $27 million
forecast as at December 31, 2009.
During 2010 FortisAlberta continued with the replacement of conventional
customer meters with AMI technology. The capital cost of the AMI project is
expected to be approximately $126 million (excluding $15 million for the pilot
program). To the end of 2010, $115 million has been spent on this project. For
further information related to this project, refer to the "Material Regulatory
Decisions and Applications - FortisAlberta" section of this media release.
In May 2010 Fortis Turks and Caicos received delivery of one of two
diesel-powered generating units that have a combined generating capacity of
approximately 18 MW. The first unit came into service in January 2011. The
delivery of the second unit is anticipated in February 2011.
In October 2010 the Corporation, in partnership with Columbia Power Corporation
and Columbia Basin Trust ("CPC/CBT"), concluded definitive agreements to
construct the 335-MW Waneta Expansion at an estimated cost of approximately $900
million. The facility is sited adjacent to the Waneta Dam and powerhouse
facilities on the Pend d'Oreille River, south of Trail, British Columbia.
CPC/CBT are both 100% owned corporations of the Government of British Columbia.
Fortis owns a controlling 51% interest in the Waneta Expansion Limited
Partnership and will operate and maintain the non-regulated investment when the
Waneta Expansion comes into service, which is expected in spring 2015.
SNC-Lavalin was awarded a contract for approximately $590 million to design and
build the Waneta Expansion. Construction began in November 2010 and
approximately $75 million was incurred on this capital project in 2010. The
Waneta Expansion will be included in the Canal Plant Agreement and will receive
fixed energy and capacity entitlements based upon long-term average water flows,
thereby significantly reducing hydrologic risk associated with the project. The
energy, approximately 630 GWh, (and associated capacity required to deliver such
energy) for the Waneta Expansion will be sold to BC Hydro under a long-term
energy purchase agreement which has been executed. The surplus capacity, equal
to 234 MW on an average annual basis, will be sold to FortisBC under a long-term
capacity purchase agreement, which was accepted by the BCUC in September 2010.
Over the next five years, consolidated gross capital expenditures are expected
to approach $5.5 billion. Of the capital spending, approximately 63% is expected
to be incurred at the Regulated Electric Utilities, driven by FortisAlberta and
FortisBC. Approximately 20% and 17% is expected to be incurred at the Regulated
Gas Utilities and at non-regulated operations, respectively. Capital
expenditures at the Regulated Utilities are subject to regulatory approval.
A breakdown of forecast gross consolidated capital expenditures for 2011 by
segment is provided in the following table.
----------------------------------------------------------------------------
Forecast Gross Consolidated Capital Expenditures (Unaudited) (1)
Year Ended December 31, 2011
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Elec- Regu- Elec- Non-
tric lated tric Regu-
Terasen New- Utili- Utili- Utili- lated
Gas Fortis found- ties - ties - ties - - Fortis
Compa- Alberta Fortis land Cana- Cana- Carib- Utility Proper-
nies (2) BC Power dian dian bean (3) ties Total
----------------------------------------------------------------------------
281 420 99 73 46 919 83 183 27 1,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2011. Excludes forecast capitalized amortization and non-cash
equity component of the allowance for funds used during construction.
(2) Includes forecast payments to be made to AESO for investment in
transmission capital projects
(3) Includes forecast non-regulated generation and corporate capital
expenditures
Significant capital projects for 2011 include: (i) continuation of construction
of the non-regulated Waneta Expansion; (ii) continued implementation of the new
customer information system and related call centres at TGI; (iii) completion of
construction of the LNG storage facility at TGVI; (iv) completion of the Fraser
River South Bank South Arm Rehabilitation Project at TGI; (iv) completion of the
implementation of AMI technology at FortisAlberta; and (v) completion of the
Okanagan Transmission Reinforcement Project at FortisBC.
CREDIT FACILITIES
As at December 31, 2010 the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.1 billion, of which $1.4 billion was
unused, including $435 million unused under the Corporation's $600 million
committed revolving credit facility. The credit facilities are syndicated almost
entirely with the seven largest Canadian banks, with no one bank holding more
than 25% of these facilities. Approximately $2.0 billion of the total credit
facilities are committed facilities, most of which have maturities in 2012 and
2013.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
--------------------------------------------------------------------------
Credit Facilities (Unaudited) As at December 31
($ millions) Corporate Regulated Fortis
and Other Utilities Properties 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 645 1,451 13 2,109 2,153
Credit facilities
utilized:
Short-term
borrowings - (351) (7) (358) (415)
Long-term debt
(including
current portion) (165) (53) - (218) (208)
Letters of credit
outstanding (1) (122) (1) (124) (100)
--------------------------------------------------------------------------
Credit facilities
unused 479 925 5 1,409 1,430
--------------------------------------------------------------------------
--------------------------------------------------------------------------
FUTURE ACCOUNTING CHANGES
Adoption of New Accounting Standards: In February 2008 the Canadian Accounting
Standards Board ("AcSB") confirmed that Canadian GAAP for publicly accountable
enterprises would be replaced by International Financial Reporting Standards
("IFRS") for fiscal years beginning on or after January 1, 2011.
The Corporation commenced its IFRS Conversion Project in 2007 when it
established a formal project governance structure, which included the Fortis
Audit Committee, senior management and project teams from each of the Fortis
subsidiaries. Overall project governance, management and support have been
coordinated by Fortis, with an independent external advisor engaged to assist in
the IFRS conversion.
IFRS does not currently provide guidance with respect to accounting for
rate-regulated activities. Over the past two to three years, the International
Accounting Standards Board ("IASB") discussed and deliberated on the subject of
accounting for rate-regulated activities, but failed to reach a conclusion on
any of the associated technical issues. In September 2010 the IASB reconfirmed
its earlier view that matters associated with rate-regulated accounting could
not be resolved quickly. The IASB, therefore, decided to defer any further
discussion on accounting for rate-regulated activities until public consultation
on its future agenda is held, and views as to what form, if any, a future
project might take to address accounting for the effects of rate-regulated
activities are obtained. Without specific guidance on accounting for
rate-regulated activities by the IASB, a transition to IFRS would likely result
in the derecognition of some, or perhaps all, of the Corporation's regulatory
assets and liabilities, and net earnings may, as a result, be subject to
significant volatility under current application of IFRS.
The pace and outcome of the IASB's activities has put Canadian rate-regulated
entities at a significant disadvantage in terms of their ability to adopt IFRS
as of January 1, 2011. Accordingly, the AcSB has provided qualifying entities
with an option to defer their changeover to IFRS by one year. The necessary
amendments to the Canadian Institute of Chartered Accountants ("CICA") Handbook
were published by the AcSB in October 2010.
While the Corporation's IFRS Conversion Project has proceeded as planned in
preparation for the adoption of IFRS on January 1, 2011, Fortis and its
rate-regulated subsidiaries qualify for the optional one-year deferral and,
therefore, will continue to prepare their financial statements in accordance
with Part V of the CICA Handbook for all interim and annual periods ending on or
before December 31, 2011.
Due to the continued uncertainty around the timing and adoption of a
rate-regulated accounting standard by the IASB, Fortis has evaluated the option
of adopting US generally accepted accounting principles ("US GAAP"), effective
January 1, 2012. Canadian rules allow a reporting issuer to prepare and file its
financial statements in accordance with US GAAP by qualifying as a US 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 US Securities and Exchange Commission under Section 12 of the US Securities
Exchange Act of 1934, as amended (the "Exchange Act"); or (ii) is required to
file reports under Section 15(d) of the Exchange Act. The Corporation has
developed and initiated a plan to become an SEC Issuer by December 31, 2011. As
an SEC Issuer, Fortis will then be permitted to prepare and file its
consolidated financial statements in accordance with US GAAP. Barring a change
that will provide certainty as to the Corporation's ability to recognize
regulatory assets and liabilities under IFRS, Fortis expects to prepare its
consolidated financial statements in accordance with US GAAP for all interim and
annual periods beginning on or after January 1, 2012. Several other Canadian
investor-owned rate-regulated utilities are also expected to take a similar
approach to possible adoption of US GAAP in 2012.
The adoption of US GAAP in 2012 is expected to result in fewer significant
changes in the Corporation's accounting policies as compared to those that may
have resulted with the adoption of IFRS. The Corporation's application of
Canadian GAAP currently relies on US GAAP for guidance on accounting for
rate-regulated activities, which allows the economic impact of rate-regulated
activities to be properly recognized in the financial statements in a manner
consistent with the timing by which amounts are reflected in customer rates.
Fortis believes that the continued application of rate-regulated accounting, and
the associated recognition of regulatory assets and liabilities under US GAAP,
more accurately reflects the impact that rate regulation has on the
Corporation's consolidated financial position and results of operations.
The Corporation's plan to adopt US GAAP effective January 1, 2012 consists of
the following three phases:
Phase I - Scoping and Diagnostics: This phase consists of project initiation and
awareness, identification of high-level differences between US GAAP and Canadian
GAAP and project planning and resourcing. Work on Phase I commenced in the
fourth quarter of 2010 and is scheduled for completion by mid-year 2011.
Phase II - Analysis and Development: This phase consists of detailed diagnostics
and evaluation of the financial impacts of adopting US GAAP; identification and
design of operational and financial business processes; and development of
required solutions to address identified issues. Phase II of the plan commenced
in January 2011 and is scheduled for completion by the third quarter of 2011.
Phase III - Implementation and Review: This phase involves implementation of the
changes required by the Corporation to prepare and file its consolidated
financial statements in accordance with US GAAP beginning in 2012 and
communication of the associated impacts. Phase III will commence in the second
quarter of 2011 and will conclude when the Corporation issues its first annual
audited US GAAP consolidated financial statements for the year ending December
31, 2012. Commencing with the first quarter of 2012, the Corporation's unaudited
interim consolidated financial statements will be prepared in accordance with US
GAAP.
The Corporation's IFRS project advisors will continue to advise the Corporation
on accounting related matters with respect to the adoption of US GAAP. Legal
counsel has also been engaged to assist with securities' filings and other legal
matters associated with the adoption of US GAAP.
OUTLOOK
The Corporation's significant capital program, which is expected to be
approximately $1.2 billion in 2011 and approach $5.5 billion over the next five
years, including work on the Waneta Expansion, should drive growth in earnings
and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing
on regulated electric and natural gas utilities in the United States and Canada.
Fortis will also pursue growth in its non-regulated businesses in support of its
regulated utility growth strategy.
FORTIS INC.
Consolidated Financial Statements
For the three and 12 months ended December 31, 2010 and 2009
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at December 31
(in millions of Canadian dollars)
2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $109 $85
Accounts receivable 655 595
Prepaid expenses 17 16
Regulatory assets 241 221
Inventories 168 178
Future income taxes 14 29
------------------------------
1,204 1,124
Assets held for sale 45 -
Other assets 168 174
Regulatory assets 831 726
Future income taxes 16 17
Utility capital assets 8,202 7,693
Income producing properties 560 559
Intangible assets 324 286
Goodwill 1,553 1,560
------------------------------
$12,903 $12,139
--------------------------------------------------------------------------
--------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings $358 $415
Accounts payable and accrued charges 953 852
Dividends payable 54 3
Income taxes payable 30 23
Regulatory liabilities 60 51
Current installments of long-term debt and
capital lease obligations 56 224
Future income taxes 6 24
------------------------------
1,517 1,592
Other liabilities 308 295
Regulatory liabilities 467 423
Future income taxes 623 570
Long-term debt and capital lease obligations 5,609 5,276
Preference shares 320 320
------------------------------
8,844 8,476
------------------------------
Shareholders' equity
Common shares 2,578 2,497
Preference shares 592 347
Contributed surplus 12 11
Equity portion of convertible debentures 5 5
Accumulated other comprehensive loss (94) (83)
Retained earnings 804 763
------------------------------
3,897 3,540
Non-controlling interests 162 123
------------------------------
4,059 3,663
------------------------------
$12,903 $12,139
--------------------------------------------------------------------------
--------------------------------------------------------------------------
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
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue $1,036 $1,020 $3,664 $3,643
----------------------------------------
Expenses
Energy supply costs 507 520 1,686 1,799
Operating 228 213 828 779
Amortization 103 91 410 364
----------------------------------------
838 824 2,924 2,942
----------------------------------------
Operating income 198 196 740 701
Finance charges 85 92 350 360
----------------------------------------
Earnings before corporate taxes 113 104 390 341
Corporate taxes 19 15 67 49
----------------------------------------
Net earnings $94 $89 $323 $292
----------------------------------------
Net earnings attributable to:
Non-controlling interests $2 $3 $10 $12
Preference equity shareholders 7 5 28 18
Common equity shareholders 85 81 285 262
----------------------------------------
$94 $89 $323 $292
----------------------------------------
Earnings per common share
Basic $0.49 $0.48 $1.65 $1.54
Diluted $0.47 $0.46 $1.62 $1.51
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Balance at beginning of period $770 $682 $763 $634
Net earnings attributable to
common and preference equity
shareholders 92 86 313 280
--------------------------------------------
862 768 1,076 914
Dividends on common shares (51) - (244) (133)
Dividends on preference shares
classified as equity (7) (5) (28) (18)
--------------------------------------------
Balance at end of period $804 $763 $804 $763
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Net earnings $94 $89 $323 $292
--------------------------------------------
Other comprehensive (loss)
income
Unrealized foreign currency
translation losses on net
investments in self-
sustaining foreign operations (20) (11) (33) (90)
Gains on hedges of net
investments in self-
sustaining foreign operations 17 8 25 67
Corporate tax expense (3) (1) (4) (9)
--------------------------------------------
Unrealized foreign currency
translation losses, net of
hedging activities and tax (6) (4) (12) (32)
--------------------------------------------
Gain on derivative instruments
designated as cash flow
hedges, net of tax - - - 1
--------------------------------------------
Reclassification to earnings
of net losses on derivative
instruments previously
discontinued as cash flow
hedges, net of tax - - 1 -
--------------------------------------------
Comprehensive income $88 $85 $312 $261
--------------------------------------------
Comprehensive income
attributable to:
Non-controlling interests $2 $3 $10 $12
Preference equity
shareholders 7 5 28 18
Common equity shareholders 79 77 274 231
--------------------------------------------
$88 $85 $312 $261
--------------------------------------------------------------------------
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended December 31
(in millions of Canadian dollars)
Quarter Ended Year Ended
2010 2009 2010 2009
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Operating activities
Net earnings $94 $89 $323 $292
Items not affecting cash:
Amortization - utility
capital assets and income
producing properties 92 80 368 317
Amortization - intangible
assets 10 11 40 43
Amortization - other 1 - 2 4
Future income taxes (2) (4) (3) 5
Other 1 - (5) (8)
Change in long-term
regulatory assets and
liabilities 13 (5) 9 25
--------------------------------------------
209 171 734 678
Change in non-cash operating
working capital (8) (100) 49 (41)
--------------------------------------------
201 71 783 637
--------------------------------------------
Investing activities
Change in other assets and
other liabilities (1) 3 - (1)
Capital expenditures -
utility capital assets (336) (241) (1,008) (966)
Capital expenditures -
income producing properties (5) (11) (19) (26)
Capital expenditures -
intangible assets (29) (9) (46) (32)
Contributions in aid of
construction 26 16 67 56
Proceeds on sale of utility
capital assets 12 - 15 1
Business acquisitions - (70) - (77)
--------------------------------------------
(333) (312) (991) (1,045)
--------------------------------------------
Financing activities
Change in short-term
borrowings (52) 79 (56) 8
Proceeds from long-term
debt, net of issue costs 523 119 523 729
Repayments of long-term debt
and capital lease
obligations (114) (24) (329) (172)
Net (repayments) borrowings
under committed credit
facilities (185) 40 8 (14)
Advances from (to) non-
controlling interests 44 - 45 (5)
Issue of common shares, net
of costs 22 14 80 46
Issue of preference shares,
net of costs - - 242 -
Dividends
Common shares (51) - (244) (133)
Preference shares (7) (5) (28) (18)
Subsidiary dividends paid
to non-controlling
interests (3) (2) (9) (10)
--------------------------------------------
177 221 232 431
--------------------------------------------
Effect of exchange rate
changes on cash and cash
equivalents - (1) - (4)
--------------------------------------------
Change in cash and cash
equivalents 45 (21) 24 19
Cash and cash equivalents,
beginning of period 64 106 85 66
--------------------------------------------------------------------------
Cash and cash equivalents, end
of period $109 $85 $109 $85
--------------------------------------------------------------------------
--------------------------------------------------------------------------
SEGMENTED INFORMATION (Unaudited)
Information by reportable segment is as follows:
REGULATED
--------------------------------------------------------------
Gas
Utilities Electric Utilities
--------------------------------------------------------------
Quarter Ended Terasen Elec-
December 31, Gas Other Total tric
2010 Companies Fortis Fortis NF Cana- Electric Carib-
($ millions) -Canadian Alberta BC Power dian(1) Canadian bean
----------------------------------------------------------------------------
Revenue 480 99 73 152 87 411 84
Energy supply
costs 277 - 23 102 59 184 51
Operating
expenses 87 37 21 15 12 85 13
Amortization 27 32 10 12 5 59 9
----------------------------------------------------------------------------
Operating
income 89 30 19 23 11 83 11
Finance
charges 29 14 8 9 5 36 5
Corporate tax
expense
(recovery) 15 (1) 1 4 1 5 -
----------------------------------------------------------------------------
Net earnings
(loss) 45 17 10 10 5 42 6
Non-
controlling
interests - - - 1 - 1 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 45 17 10 9 5 41 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 134
Identifiable
assets 4,319 2,144 1,263 1,191 646 5,244 779
----------------------------------------------------------------------------
Total assets 5,227 2,371 1,484 1,191 709 5,755 913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 71 121 40 22 15 198 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
December 31,
2009
($ millions)
----------------------------------------------------------------------------
Revenue 497 86 69 146 79 380 85
Energy supply
costs 300 - 22 99 50 171 50
Operating
expenses 79 34 20 13 12 79 13
Amortization 26 24 9 12 5 50 8
----------------------------------------------------------------------------
Operating
income 92 28 18 22 12 80 14
Finance
charges 30 14 8 9 6 37 4
Corporate tax
expense
(recovery) 14 (1) 2 4 (1) 4 -
----------------------------------------------------------------------------
Net earnings
(loss) 48 15 8 9 7 39 10
Non-
controlling
interests - - - 1 - 1 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 48 15 8 8 7 38 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,086 1,892 1,141 1,165 618 4,816 799
----------------------------------------------------------------------------
Total assets 4,994 2,119 1,362 1,165 681 5,327 940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 70 92 36 22 13 163 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
-------------------------------------
Quarter Ended
December 31, Fortis Corporate Inter-
2010 Generation Fortis and segment
($ millions) (2) Properties Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 9 57 7 (12) 1,036
Energy supply
costs - - - (5) 507
Operating
expenses 2 38 3 - 228
Amortization 1 5 2 - 103
----------------------------------------------------------------------------
Operating
income 6 14 2 (7) 198
Finance
charges - 6 16 (7) 85
Corporate tax
expense
(recovery) 1 1 (3) - 19
----------------------------------------------------------------------------
Net earnings
(loss) 5 7 (11) - 94
Non-
controlling
interests - - - - 2
Preference
share
dividends - - 7 - 7
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 7 (18) - 85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,553
Identifiable
assets 324 576 505 (397) 11,350
----------------------------------------------------------------------------
Total assets 324 576 505 (397) 12,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 77 5 - - 370
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
December 31,
2009
($ millions)
----------------------------------------------------------------------------
Revenue 5 54 6 (7) 1,020
Energy supply
costs - - - (1) 520
Operating
expenses 2 37 5 (2) 213
Amortization 1 5 1 - 91
----------------------------------------------------------------------------
Operating
income 2 12 - (4) 196
Finance
charges - 5 20 (4) 92
Corporate tax
expense
(recovery) 1 2 (6) - 15
----------------------------------------------------------------------------
Net earnings
(loss) 1 5 (14) - 89
Non-
controlling
interests (1) - - - 3
Preference
share
dividends - - 5 - 5
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 2 5 (19) - 81
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,560
Identifiable
assets 200 576 491 (389) 10,579
----------------------------------------------------------------------------
Total assets 200 576 491 (389) 12,139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) - 10 3 - 261
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect contribution from the Vaca hydroelectric generating
facility in Belize which was commissioned in March 2010.
(3) Relates to cash payments to acquire or construct utility capital assets,
including amounts for AESO transmision capital projects, income
producing properties and intangible assets, as reflected in the
consolidated statement of cash flows
REGULATED
--------------------------------------------------------------
Gas
Utilities Electric Utilities
--------------------------------------------------------------
Annual
December 31, Terasen
2010 Gas Other Elec-
($ millions) Companies Cana- Total tric
- Fortis Fortis NF dian Electric Carib-
Canadian Alberta BC Power (1) Canadian bean
----------------------------------------------------------------------------
Revenue 1,547 388 266 555 331 1,540 335
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 288 121 79 88 48 336 50
Finance
charges 113 54 32 36 21 143 17
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 1,191 646 5,244 779
----------------------------------------------------------------------------
Total assets 5,227 2,371 1,484 1,191 709 5,755 913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 253 379 139 78 48 644 72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Annual
December 31,
2009
($ millions)
----------------------------------------------------------------------------
Revenue 1,663 331 253 527 285 1,396 339
Energy supply
costs 1,022 - 72 346 183 601 192
Operating
expenses 268 132 70 52 38 292 54
Amortization 102 94 37 45 19 195 37
----------------------------------------------------------------------------
Operating
income 271 105 74 84 45 308 56
Finance
charges 121 50 32 35 19 136 16
Corporate tax
expense
(recovery) 33 (5) 5 16 6 22 2
----------------------------------------------------------------------------
Net earnings
(loss) 117 60 37 33 20 150 38
Non-
controlling
interests - - - 1 - 1 11
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 117 60 37 32 20 149 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 141
Identifiable
assets 4,086 1,892 1,141 1,165 618 4,816 799
----------------------------------------------------------------------------
Total assets 4,994 2,119 1,362 1,165 681 5,327 940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 246 407 115 74 46 642 92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
-------------------------------------
Annual
December 31,
2010
($ millions) Fortis Inter-
Generation Fortis Corporate segment
(2) Properties and Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 36 226 30 (50) 3,664
Energy supply
costs 1 - - (25) 1,686
Operating
expenses 9 151 16 (5) 828
Amortization 4 18 7 - 410
----------------------------------------------------------------------------
Operating
income 22 57 7 (20) 740
Finance
charges - 24 73 (20) 350
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 324 576 505 (397) 11,350
----------------------------------------------------------------------------
Total assets 324 576 505 (397) 12,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 84 19 1 - 1,073
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Annual
December 31,
2009
($ millions)
----------------------------------------------------------------------------
Revenue 39 219 27 (40) 3,643
Energy supply
costs 2 - - (18) 1,799
Operating
expenses 11 146 14 (6) 779
Amortization 5 17 8 - 364
----------------------------------------------------------------------------
Operating
income 21 56 5 (16) 701
Finance
charges 2 22 79 (16) 360
Corporate tax
expense
(recovery) 3 10 (21) - 49
----------------------------------------------------------------------------
Net earnings
(loss) 16 24 (53) - 292
Non-
controlling
interests - - - - 12
Preference
share
dividends - - 18 - 18
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 16 24 (71) - 262
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,560
Identifiable
assets 200 576 491 (389) 10,579
----------------------------------------------------------------------------
Total assets 200 576 491 (389) 12,139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(3) 14 26 4 - 1,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Algoma Power from October 2009, the date of acquisition by
FortisOntario
(2) Results reflect the expiry, on April 30, 2009, at the end of a 100-year
term, of the 75 MW of water-right entitlement associated with the
Rankine hydroelectric generating facility at Niagara Falls. Results also
reflect contribution from the Vaca hydroelectric generating facility in
Belize which was commissioned in March 2010.
(3) Relates to cash payments to acquire or construct utility capital assets,
including amounts for AESO transmision capital projects, income
producing properties and intangible assets, as reflected in the
consolidated statement of cash flows
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada. With
total assets of $12.9 billion and fiscal 2010 revenue totalling approximately
$3.7 billion, the Corporation serves approximately 2,100,000 gas and electricity
customers. Its regulated holdings include electric distribution utilities in
five Canadian provinces and three Caribbean countries and a natural gas utility
in British Columbia. Fortis owns and operates non-regulated generation assets
across Canada and in Belize and Upper New York State. It also owns and operates
hotels and commercial office and retail space primarily in Atlantic Canada.
Fortis Inc. shares are listed on the Toronto Stock Exchange and trade under the
symbol FTS.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2009 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
Dentonia Resources Ltd. (TSXV:DTA)
Gráfica de Acción Histórica
De May 2024 a Jun 2024
Dentonia Resources Ltd. (TSXV:DTA)
Gráfica de Acción Histórica
De Jun 2023 a Jun 2024
