Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved
third quarter net earnings attributable to common equity
shareholders of $45 million, or $0.24 per common share, compared to
$56 million, or $0.30 per common share, for the third quarter of
2011. Year-to-date net earnings attributable to common equity
shareholders were $228 million, or $1.20 per common share, compared
to $229 million, or $1.28 per common share, for the same period
last year.
In 2012 earnings for the third quarter and year to date were
reduced by $3.5 million and $10 million, respectively, related to
foreign exchange and CH Energy Group, Inc. ("CH Energy Group")
acquisition-related expenses. In 2011 earnings for the third
quarter and year to date were favourably impacted by a one-time $11
million after-tax merger termination fee paid to Fortis and $2.5
million of foreign exchange.
Excluding the above impacts, improved performance at the western
Canadian regulated electric utilities for the quarter was partially
offset by decreased non-regulated hydroelectric generation and a
higher loss incurred at the regulated gas utilities.
Canadian Regulated Electric Utilities, led by FortisAlberta and
FortisBC Electric, contributed earnings of $54 million, up $11
million from the third quarter of 2011. At FortisAlberta, higher
net transmission revenue, growth in energy infrastructure
investment and timing of operating expenses during 2012 were
partially offset by a lower allowed rate of return on common
shareholder's equity. At FortisBC Electric, performance was driven
by growth in energy infrastructure investment, higher
pole-attachment revenue and lower-than-expected finance
charges.
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets for approximately $55 million. FortisBC
Electric has operated and maintained the City of Kelowna's
electrical utility assets, which currently serve approximately
15,000 customers, since 2000. Closing of the transaction is subject
to certain conditions and receipt of certain approvals, including
regulatory approval. FortisBC Electric and the City of Kelowna are
working towards closing the transaction by the end of the first
quarter of 2013.
Canadian Regulated Gas Utilities incurred a loss of $6 million
compared to a loss of $4 million for the third quarter of 2011. The
third quarter is normally a period of lower customer demand due to
warmer temperatures. The higher loss largely related to the
unfavourable impact of the difference in the timing of recognition
of revenue associated with seasonal gas consumption and certain
increased regulator-approved expenses in 2012, lower capitalized
allowance for funds used during construction, and
lower-than-expected customer additions in 2012. The above items
were partially offset by higher gas transportation volumes to
industrial customers and the timing of certain operating and
maintenance expenses during 2012.
Year-to-date 2012, regulatory decisions have been received for:
(i) 2012-2013 revenue requirements at the FortisBC Energy
companies; (ii) 2012 distribution revenue requirements at
FortisAlberta; and (iii) 2012-2013 revenue requirements at FortisBC
Electric. The Alberta Utilities Commission issued a generic
decision in September 2012 on its Performance-Based Regulation
("PBR") Initiative, outlining the PBR framework applicable to
distribution utilities in Alberta for a five-year term commencing
January 1, 2013. FortisAlberta will file the required
PBR-compliance application in November 2012. A Generic Cost of
Capital ("GCOC") Proceeding to finalize 2013 cost of capital for
distribution utilities in Alberta is expected to commence late 2012
or early 2013. In British Columbia, the GCOC Proceeding to
determine cost of capital, effective January 1, 2013, continues
with an oral hearing scheduled for December 2012. Newfoundland
Power filed a general rate application in September 2012 for 2013
customer rates and cost of capital.
Caribbean Regulated Electric Utilities contributed $7 million of
earnings, compared to $6 million for the third quarter of 2011.
Fortis Turks and Caicos acquired Turks and Caicos Utilities Limited
("TCU") in August 2012 for an aggregate purchase price of
approximately $13 million (US$13 million), inclusive of debt
assumed. TCU serves more than 2,000 customers on Grand Turk and
Salt Cay with a diesel-fired generating capacity of approximately 9
megawatts ("MW"). The utility currently operates pursuant to a
50-year licence that expires in 2036.
Non-Regulated Fortis Generation contributed $5 million to
earnings compared to $8 million for the same quarter last year. The
decrease mainly related to lower production in Belize due to lower
rainfall.
Fortis Properties delivered earnings of $8 million, compared to
$9 million for the third quarter of 2011, reflecting lower
occupancy at hotel operations in Atlantic Canada and central
Canada, partially offset by earnings contribution from the Hilton
Suites Winnipeg Airport hotel, which was acquired in October 2011.
In October 2012 Fortis Properties acquired the 126-room StationPark
All Suite Hotel in London, Ontario for approximately $13
million.
Corporate and other expenses were $23 million compared to $6
million for the third quarter of 2011. Excluding the $11 million
after-tax termination fee paid to Fortis in July 2011, corporate
and other expenses increased quarter over quarter, mainly as a
result of a $3 million after-tax foreign exchange loss recognized
in the third quarter of 2012 compared to a $2.5 million after-tax
net foreign exchange gain recognized in the same quarter last year.
Acquisition-related expenses associated with the CH Energy Group
transaction were approximately $0.5 million after-tax for the third
quarter of 2012.
Consolidated capital expenditures, before customer
contributions, were approximately $794 million year-to-date 2012.
At FortisBC Gas, the Customer Care Enhancement Project came into
service at the beginning of January 2012. Construction of the $900
million, 335-MW Waneta Expansion hydroelectric generating facility
("Waneta Expansion") in British Columbia continues on time and on
budget. Approximately $380 million in total has been spent on the
Waneta Expansion since construction began in late 2010.
Cash flow from operating activities was $804 million
year-to-date 2012, up $120 million from the same period last year,
driven by favourable changes in regulatory deferral accounts and
receivables and the collection of increased depreciation and
amortization expense in customer rates.
Fortis announced in February 2012 that it had entered into an
agreement to acquire CH Energy Group for an aggregate purchase
price of approximately US$1.5 billion, including the assumption of
approximately US$500 million of debt on closing. CH Energy Group's
main business, Central Hudson Gas & Electric Corporation
("Central Hudson"), serves approximately 375,000 electric and gas
customers in New York State's Mid-Hudson River Valley. The
transaction received CH Energy Group shareholder approval in June
2012 and regulatory approval from the Federal Energy Regulatory
Commission and the Committee on Foreign Investment in the United
States in July 2012. The waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976 expired in October 2012,
satisfying another condition necessary for consummation of the
transaction. The transaction remains subject to approval by the New
York State Public Service Commission ("NYSPSC"). The acquisition is
expected to close by the end of the first quarter of 2013 and be
immediately accretive to earnings per common share of Fortis,
excluding acquisition-related expenses.
Fortis raised gross proceeds of approximately $601 million in
June 2012, upon issuance of 18,500,000 Subscription Receipts at
$32.50 each, to finance a portion of the purchase price of CH
Energy Group. The proceeds are being held by an escrow agent,
pending satisfaction of closing conditions, including receipt of
regulatory approvals, contained in the agreement to acquire CH
Energy Group. Each Subscription Receipt will entitle the holder
thereof to receive, on satisfaction of the closing conditions, one
common share of Fortis.
In October 2012 FortisAlberta raised $125 million 40-year 3.98%
unsecured debentures, largely in support of its capital expenditure
program.
Fortis corporate debt is rated A- by Standard & Poor's and
A(low) by DBRS.
Fortis retroactively adopted accounting principles generally
accepted in the United States ("US GAAP"), effective January 1,
2012, with the restatement of prior periods. The adoption of US
GAAP did not have a material impact on the Corporation's earnings
per common share for the third quarter of 2012 or 2011.
"Our utilities are focused on completing their remaining capital
projects for 2012. Our capital expenditures for the year are
expected to reach $1.3 billion," says Stan Marshall, President and
Chief Executive Officer, Fortis Inc. "Over the five-year period to
2016, our capital program is expected to total $5.5 billion;
Central Hudson's capital program from 2013 through 2016 will add a
further approximate $0.5 billion," he explains.
"Our largest utilities are busy with significant regulatory
processes, including those related to the determination of 2013
allowed returns," says Marshall.
"Also on the regulatory front, we are focused on closing the CH
Energy Group transaction by the end of the first quarter of 2013.
Approval of the transaction by the NYSPSC is the one remaining
significant regulatory matter," concludes Marshall.
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2012
Dated November 1, 2012
FORWARD-LOOKING STATEMENT
The following Fortis Inc. ("Fortis" or the "Corporation")
Management Discussion and Analysis ("MD&A") has been prepared
in accordance with National Instrument 51-102 - Continuous
Disclosure Obligations. Financial information for 2012 and
comparative periods contained in the MD&A has been prepared in
accordance with accounting principles generally accepted in the
United States ("US GAAP") and is presented in Canadian dollars
unless otherwise specified. The MD&A should be read in
conjunction with the following: (i) the interim unaudited
consolidated financial statements and notes thereto for the three
and nine months ended September 30, 2012, prepared in accordance
with US GAAP; (ii) the audited consolidated financial statements
and notes thereto for the year ended December 31, 2011, prepared in
accordance with US GAAP and voluntarily filed on the System for
Electronic Document Analysis and Retrieval ("SEDAR") by Fortis on
March 16, 2012; (iii) the audited consolidated financial statements
and notes thereto for the year ended December 31, 2011, prepared in
accordance with Canadian generally accepted accounting principles
("Canadian GAAP"); (iv) the "Supplemental Interim Consolidated
Financial Statements for the Year Ended December 31, 2011
(Unaudited)" contained in the above-noted voluntary filing, which
provides a detailed reconciliation between the Corporation's
interim unaudited consolidated 2011 Canadian GAAP financial
statements and interim unaudited consolidated 2011 US GAAP
financial statements; and (v) the MD&A for the year ended
December 31, 2011 included in the Corporation's 2011 Annual
Report.
Fortis includes forward-looking information in the MD&A
within the meaning of applicable securities laws in Canada
("forward-looking information"). The purpose of the forward-looking
information is to provide management's expectations regarding the
Corporation's future growth, results of operations, performance,
business prospects and opportunities, and it may not be appropriate
for other purposes. All forward-looking information is given
pursuant to the safe harbour provisions of applicable Canadian
securities legislation. The words "anticipates", "believes",
"budgets", "could", "estimates", "expects", "forecasts", "intends",
"may", "might", "plans", "projects", "schedule", "should", "will",
"would" and similar expressions are often intended to identify
forward-looking information, although not all forward-looking
information contains these identifying words. The forward-looking
information reflects management's current beliefs and is based on
information currently available to the Corporation's management.
The forward-looking information in the MD&A includes, but is
not limited to, statements regarding: the Corporation's
consolidated forecast gross capital expenditures for 2012 and in
total over the five-year period 2012 through 2016; the nature,
timing and amount of certain capital projects and their expected
costs and time to complete; the expectation that the Corporation's
significant capital expenditure program should support continuing
growth in earnings and dividends; forecast midyear rate base; the
expectation that cash required to complete subsidiary capital
expenditure programs will be sourced from a combination of cash
from operations, borrowings under credit facilities, equity
injections from Fortis and long-term debt offerings; the expected
consolidated long-term debt maturities and repayments on average
annually over the next five years; except for debt at the Exploits
River Hydro Partnership ("Exploits Partnership"), the expectation
that the Corporation and its subsidiaries will remain compliant
with debt covenants throughout the remainder of 2012; the expected
timing of filing regulatory applications and of receipt of
regulatory decisions; the expected timing of the closing of the
acquisition of CH Energy Group, Inc. ("CH Energy Group") by Fortis
and the expectation that the acquisition will be immediately
accretive to earnings per common share, excluding
acquisition-related expenses; an expected favourable impact on the
Corporation's earnings in future periods upon final enactment of
legislative changes to Part VI.1 taxes; the expectation of greater
risk under Performance-Based Regulation ("PBR") that
FortisAlberta's earnings may be negatively impacted; and the
expectation that FortisBC Electric and the City of Kelowna will
work towards closing the proposed acquisition of the City of
Kelowna's electrical utility assets by FortisBC Electric by the end
of the first quarter of 2013.
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 variability in interest
rates; no significant operational disruptions or environmental
liability due to a catastrophic event or environmental upset caused
by severe weather, other acts of nature or other major events; the
continued ability to maintain the gas and electricity systems to
ensure their continued performance; no severe and prolonged
downturn in economic conditions; no significant decline in capital
spending; no material capital project and financing cost overrun
related to the construction of the Waneta Expansion hydroelectric
generating facility; sufficient liquidity and capital resources;
the expectation that the Corporation will receive appropriate
compensation from the Government of Belize ("GOB") for fair value
of the Corporation's investment in Belize Electricity that was
expropriated by the GOB; the expectation that Belize Electric
Company Limited ("BECOL") will not be expropriated by the GOB; the
expectation that the Corporation will receive fair compensation
from the Government of Newfoundland and Labrador related to the
expropriation of the Exploits Partnership's hydroelectric assets
and water rights; 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 foreign exchange rates, natural gas commodity
prices and fuel prices; 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, fuel and electricity
supply; continuation and regulatory approval of power supply and
capacity purchase contracts; the receipt of regulatory approval
from the New York State Public Service Commission, absent material
conditions imposed, required in connection with the acquisition of
CH Energy Group; the ability to fund defined benefit pension plans,
earn the assumed long-term rates of return on the related assets
and recover net pension costs in customer rates; the absence of
significant changes in government energy plans and environmental
laws that may materially negatively 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; the
ability to report under US GAAP beyond 2014 or the adoption of
International Financial Reporting Standards ("IFRS") after 2014
that allows for the recognition of regulatory assets and
liabilities; the continued tax-deferred treatment of earnings from
the Corporation's Caribbean operations; continued maintenance of
information technology ("IT") infrastructure; continued 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, including increased risk at
FortisAlberta associated with the adoption of PBR under a five-year
term commencing in 2013; interest rate risk, including the
uncertainty of the impact a continuation of a low interest rate
environment may have on allowed rates of return on common
shareholders' equity of the Corporation's regulated utilities;
operating and maintenance risks; risk associated with changes in
economic conditions; capital project budget overrun, completion and
financing risk in the Corporation's non-regulated business; capital
resources and liquidity risk; risk associated with the amount of
compensation to be paid to Fortis for its investment in Belize
Electricity that was expropriated by the GOB; the timeliness of the
receipt of the compensation and the ability of the GOB to pay the
compensation owing to Fortis; risk that the GOB may expropriate
BECOL; an ultimate resolution of the expropriation of the
hydroelectric assets and water rights of the Exploits Partnership
that differs from that which is currently expected by management;
weather and seasonality risk; commodity price risk; the continued
ability to hedge foreign exchange risk; counterparty risk;
Competitiveness of natural gas; natural gas, fuel and
electricity supply risk; risk associated with the continuation,
renewal, replacement and/or regulatory approval of power supply and
capacity purchase contracts; risks relating to the ability to close
the acquisition of CH Energy Group, the timing of such closing and
the realization of the anticipated benefits of the acquisition;
risk of having to raise alternative capital to finance the
acquisition of CH Energy Group if the closing of the acquisition
occurs subsequent to June 30, 2013; the risk associated with
defined benefit pension plan performance and funding requirements;
risks related to FortisBC Energy (Vancouver Island) Inc.;
environmental risks; insurance coverage risk; risk of loss of
licences and permits; risk of loss of service area; risk of not
being able to report under US GAAP beyond 2014 or risk that IFRS
does not have an accounting standard for rate-regulated entities by
the end of 2014 allowing for the recognition of regulatory assets
and liabilities; risks related to changes in tax legislation; risk
of failure of IT infrastructure; risk of not being able to access
First Nations lands; labour relations risk; human resources risk;
and risk of unexpected outcomes of legal proceedings currently
against the Corporation. For additional information with respect to
the Corporation's risk factors, reference should be made to the
Corporation's continuous disclosure materials filed from time to
time with Canadian securities regulatory authorities and to the
heading "Business Risk Management" in the MD&A for the three
and nine months ended September 30, 2012 and for the year ended
December 31, 2011.
All forward-looking information in the MD&A is qualified in
its entirety by the above cautionary statements and, except as
required by law, the Corporation undertakes no obligation to revise
or update any forward-looking information as a result of new
information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in
Canada, serving more than 2,000,000 gas and electricity customers.
Its regulated holdings include electric utilities in five Canadian
provinces and two Caribbean countries and a natural gas utility in
British Columbia, Canada. Fortis owns non-regulated generation
assets, primarily hydroelectric, across Canada and in Belize and
Upstate New York, and hotels and commercial office and retail space
in Canada. Year-to-date September 30, 2012, the Corporation's
electricity distribution systems met a combined peak demand of
approximately 5,225 megawatts ("MW") and its gas distribution
system met a peak day demand of 1,335 terajoules ("TJ"). For
additional information on the Corporation's business segments,
refer to Note 1 to the Corporation's interim unaudited consolidated
financial statements for the three and nine months ended September
30, 2012 and to the "Corporate Overview" section of the 2011 Annual
MD&A.
The key goals of the Corporation's regulated utilities are to
operate sound gas and electricity distribution systems, deliver gas
and electricity safely and reliably at the lowest reasonable cost
and conduct business in an environmentally responsible manner. The
Corporation's main business, utility operations, is highly
regulated and the earnings of the Corporation's regulated utilities
are primarily determined under cost of service ("COS")
regulation.
Generally under COS regulation, the respective regulatory
authority sets customer gas and/or electricity rates to permit a
reasonable opportunity for the utility to recover, on a timely
basis, estimated costs of providing service to customers, including
a fair rate of return on a regulatory deemed or targeted capital
structure applied to an approved regulatory asset value ("rate
base"). The ability of a regulated utility to recover prudently
incurred costs of providing service and earn the regulator-approved
rate of return on common shareholders' equity ("ROE") and/or rate
of return on rate base assets ("ROA") depends on the utility
achieving the forecasts established in the rate-setting processes.
As such, earnings of regulated utilities are generally impacted by:
(i) changes in the regulator-approved allowed ROE and/or ROA; (ii)
changes in rate base; (iii) changes in energy sales or gas delivery
volumes; (iv) changes in the number and composition of customers;
(v) variances between actual expenses incurred and forecast
expenses used to determine revenue requirements and set customer
rates; and (vi) timing differences within an annual financial
reporting period, between when actual expenses are incurred and
when they are recovered from customers in rates. When forward test
years are used to establish revenue requirements and set base
customer rates, these rates are not adjusted as a result of actual
COS being different from that which was estimated, other than for
certain prescribed costs that are eligible to be deferred on the
balance sheet. In addition, the Corporation's regulated utilities,
where applicable, are permitted by their respective regulatory
authority to flow through to customers, without markup, the cost of
natural gas, fuel and/or purchased power through base customer
rates and/or the use of rate stabilization and other
mechanisms.
SIGNIFICANT ITEMS
Pending Acquisition of CH Energy Group, Inc.: In February 2012
Fortis announced that it had entered into an agreement to acquire
CH Energy Group, Inc. ("CH Energy Group") for US$65.00 per common
share in cash, for an aggregate purchase price of approximately
US$1.5 billion, including the assumption of approximately US$500
million of debt on closing. CH Energy Group is an energy delivery
company headquartered in Poughkeepsie, New York. Its main business,
Central Hudson Gas & Electric Corporation, is a regulated
transmission and distribution ("T&D") utility serving
approximately 300,000 electric and 75,000 natural gas customers in
eight counties of New York State's Mid-Hudson River Valley. The
transaction received CH Energy Group shareholder approval in June
2012 and regulatory approval from the Federal Energy Regulatory
Commission and the Committee on Foreign Investment in the United
States in July 2012. In addition, the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in
October 2012, satisfying another condition necessary for
consummation of the transaction.
The transaction remains subject to approval by the New York
State Public Service Commission ("NYSPSC") and satisfaction of
customary closing conditions. The application for approval of the
transaction by the NYSPSC was jointly filed by Fortis and CH Energy
Group in April 2012. The acquisition is expected to close by the
end of the first quarter of 2013 and be immediately accretive to
earnings per common share, excluding acquisition-related
expenses.
During the third quarter and year-to-date 2012, the
Corporation's earnings were reduced by $0.5 million and $7.5
million, respectively, associated with CH Energy Group after-tax
acquisition-related expenses.
Subscription Receipts Offering: In June 2012, to finance a
portion of the pending acquisition of CH Energy Group, Fortis sold
18,500,000 Subscription Receipts at $32.50 each through a
bought-deal offering underwritten by a syndicate of underwriters
led by CIBC World Markets Inc., Scotia Capital Inc. and TD
Securities Inc., realizing gross proceeds of approximately $601
million. The gross proceeds from the sale of the Subscription
Receipts are being held by an escrow agent, pending satisfaction of
closing conditions, including receipt of regulatory approvals,
included in the agreement to acquire CH Energy Group (the "Release
Conditions"). The Subscription Receipts began trading on the
Toronto Stock Exchange on June 27, 2012 under the symbol
"FTS.R".
Each Subscription Receipt will entitle the holder thereof to
receive, on satisfaction of the Release Conditions and without
payment of additional consideration, one common share of Fortis and
a cash payment equal to the dividends declared on Fortis common
shares to holders of record during the period from June 27, 2012 to
the date of issuance of the common shares in respect of the
Subscription Receipts.
If the Release Conditions are not satisfied by June 30, 2013, or
if the agreement and plan of merger relating to the acquisition of
CH Energy Group is terminated prior to such time, holders of
Subscription Receipts shall be entitled to receive from the escrow
agent an amount equal to the full subscription price thereof plus
their pro rata share of the interest earned on such amount.
For further information on the pending acquisition and the
related Subscription Receipts offering, refer to the "Business Risk
Management" section of this MD&A.
Receipt of Regulatory Decisions: Year-to-date 2012, regulatory
decisions have been received for 2012-2013 revenue requirements at
the FortisBC Energy companies, 2012 distribution revenue
requirements at FortisAlberta and, recently in August, for
2012-2013 revenue requirements at FortisBC Electric. The Alberta
Utilities Commission ("AUC") issued a generic decision in September
2012 on its Performance-Based Regulation ("PBR") Initiative
outlining the PBR framework applicable to distribution utilities in
Alberta, including FortisAlberta, for a five-year term commencing
January 1, 2013. For further information on these regulatory
decisions, refer to the "Regulatory Highlights" and "Business Risk
Management" sections of this MD&A.
Part VI.1 Tax: Under the terms of the Corporation's first
preference shares, the Corporation is subject to tax under Part
VI.1 of the Income Tax Act (Canada) associated with dividends on
its first preference shares. For corporations subject to Part VI.1
tax, there is an equivalent Part I tax deduction. As permitted
under the Income Tax Act (Canada), a corporation may allocate its
Part VI.1 tax liability and equivalent Part I tax deduction to its
related subsidiaries. In the past, Fortis has allocated these items
to Maritime Electric, Newfoundland Power and FortisOntario.
Upon transition to US GAAP, the Corporation reduced its
consolidated opening 2012 retained earnings by $20 million to
reflect the impact of differences between enacted and substantively
enacted tax legislation associated with prior assessments and
payments of Part VI.1 taxes, and the recovery of Part I taxes. The
adjustment was done as US GAAP requires tax provisions to be based
on enacted legislation versus substantively enacted legislation. A
number of legislative amendments to Part VI.1 tax in Canada have
yet to be enacted. The above-noted transitional US GAAP adjustment
will reverse through the Corporation's earnings in future periods
when the legislation is finally enacted, which is expected in 2013,
or as reassessment of corporate taxation years, upon which the
enacted versus the substantively enacted rates were used to
calculate taxes payable under US GAAP, become statute barred. The
statute-barred reversals will occur between 2012 and 2016 and will
increase earnings during these years. During the third quarter of
2012, Newfoundland Power recorded a favourable $2.5 million
adjustment to income taxes associated with statute-barred Part VI.1
taxes.
Purchase of the Electricity Distribution Assets in Port
Colborne: In April 2012 FortisOntario exercised its option to
purchase all of the assets previously leased by the Company under
an operating lease agreement with the City of Port Colborne for the
purchase option price of approximately $7 million. The exercise of
the purchase option, which qualifies as a business combination,
provides ownership and legal title to all of the assets, including
equipment, real property and distribution assets, which constitute
the electricity distribution system in Port Colborne.
Acquisition of Turks and Caicos Utilities Limited: In August
2012 Fortis Turks and Caicos acquired Turks and Caicos Utilities
Limited ("TCU") for an aggregate purchase price of approximately
$13 million (US$13 million), inclusive of debt assumed of $5
million (US$5 million). TCU is a regulated electric utility
operating pursuant to a 50-year licence expiring in 2036. The
utility serves more than 2,000 residential and commercial customers
on Grand Turk and Salt Cay with a diesel-fired generating capacity
of approximately 9 MW.
Hotel Acquisition: In October 2012 Fortis Properties acquired
the 126-room StationPark All Suite Hotel ("StationPark Hotel") in
London, Ontario for approximately $13 million.
Pending Acquisition of the Electrical Utility Assets from the
City of Kelowna: FortisBC Electric has offered to purchase the City
of Kelowna's electrical utility assets, which currently serve
approximately 15,000 customers, for approximately $55 million.
FortisBC Electric provides the City of Kelowna with electricity
under a wholesale tariff and has operated and maintained the City
of Kelowna's electrical utility assets since 2000. Closing of the
transaction is subject to certain conditions and receipt of certain
approvals, including regulatory approval. The parties are working
towards closing the transaction by the end of the first quarter of
2013.
Expropriation of Shares in Belize Electricity: The Government of
Belize ("GOB") expropriated the Corporation's common share
ownership in Belize Electricity in June 2011. The Corporation is
challenging the legality of the expropriation in the Belize Courts.
Although the GOB initiated contact with Fortis, there have been no
settlement negotiations to date on the fair value compensation
owing to Fortis as a result of the expropriation. For further
information, refer to the "Business Risk Management" section of
this MD&A.
Transition to US GAAP: Effective January 1, 2012, Fortis
retroactively adopted US GAAP with the restatement of comparative
reporting periods. For further information, refer to the "New
Accounting Standards and Policies" section of this MD&A.
Re-Organization of Non-Regulated Generation Operations:
Effective July 1, 2012, the legal ownership of the six small
non-regulated hydroelectric generating facilities in eastern
Ontario, with a combined generating capacity of 8 MW, was
transferred from Fortis Properties to a limited partnership
directly held by Fortis. FortisBC Holdings Inc. ("FHI") assumed
management responsibility for the operations of the above-noted
facilities, as well as for the four non-regulated hydroelectric
generating facilities in Upstate New York, with a combined
generating capacity of 23 MW, owned by FortisUS Energy Corporation
("FortisUS Energy").
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings
per common share as the primary measure of performance. The
Corporation's business is segmented by franchise area and,
depending on regulatory requirements, by the nature of the assets.
Key financial highlights for the third quarter and year-to-date
periods ended September 30, 2012 and September 30, 2011 are
provided in the following table.
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Consolidated Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions, except
for common share
data) 2012 2011 Variance 2012 2011 Variance
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Revenue 714 699 15 2,655 2,704 (49)
Energy Supply Costs 235 246 (11) 1,092 1,207 (115)
Operating Expenses 203 200 3 621 619 2
Depreciation and
Amortization 118 104 14 351 309 42
Other Income
(Expenses), Net 1 22 (21) (2) 34 (36)
Finance Charges 93 89 4 276 274 2
Income Taxes 7 12 (5) 44 59 (15)
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Net Earnings 59 70 (11) 269 270 (1)
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Net Earnings
Attributable to:
Non-Controlling
Interests 3 3 - 7 7 -
Preference Equity
Shareholders 11 11 - 34 34 -
Common Equity
Shareholders 45 56 (11) 228 229 (1)
----------------------------------------------------------------------------
Net Earnings 59 70 (11) 269 270 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic Earnings per
Common Share ($) 0.24 0.30 (0.06) 1.20 1.28 (0.08)
Diluted Earnings per
Common Share ($) 0.24 0.30 (0.06) 1.19 1.27 (0.08)
Weighted Average
Number of Common
Shares Outstanding
(# millions) 190.2 186.5 3.7 189.6 179.5 10.1
----------------------------------------------------------------------------
Cash Flow from
Operating
Activities 221 151 70 804 684 120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- An increase in gas delivery rates and the base component of electricity
rates at most of the regulated utilities, consistent with rate
decisions, reflecting ongoing investment in energy infrastructure and
forecasted certain higher expenses recoverable from customers
-- Net transmission revenue of approximately $3.5 million recognized for
the quarter and $6.5 million recognized year to date at FortisAlberta,
as a result of the 2012 distribution revenue requirements decision
received in April 2012
-- Higher gas transportation volumes to industrial customers
-- Increased electricity sales at FortisBC Electric, Newfoundland Power,
Maritime Electric and Fortis Turks and Caicos for the quarter and year
to date and at FortisOntario for the quarter
-- The flow through in customer electricity rates of higher energy supply
costs, where applicable, at most of the regulated electric utilities
-- Growth in the number of customers, driven by FortisAlberta
-- Differences in the amount of PBR incentives refunded, and flow-through
adjustments owing, to FortisBC Electric's customers period over period
-- Higher Hospitality revenue at Fortis Properties, driven by revenue from
the Hilton Suites Winnipeg Airport hotel ("Hilton Suites Hotel"), which
was acquired in October 2011
-- Increased non-regulated hydroelectric production in Belize year to date,
due to higher rainfall
-- Approximately $1 million for the quarter and $5 million year to date of
favourable foreign exchange associated with the translation of US
dollar-denominated revenue, due to the strengthening of the US dollar
relative to the Canadian dollar period over period
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011, which reduced revenue year to date
-- The flow through in customer electricity rates of lower energy supply
costs at Caribbean Utilities for the quarter, due to a decrease in the
cost of fuel period over period
-- Lower average gas consumption by residential and commercial customers
year to date
-- Revenue at Newfoundland Power in 2011 reflected the favourable impact of
support structure arrangements with Bell Aliant Inc. ("Bell Aliant")
-- Decreased non-regulated hydroelectric production in Belize for the
quarter, due to lower rainfall
-- Decreased electricity sales at Caribbean Utilities for the quarter and
year to date and at FortisOntario year to date
Factors Contributing to Quarterly and Year-to-Date
Energy Supply Costs Variances
Favourable
-- Lower commodity cost of natural gas
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011, which reduced energy supply costs year to date
-- Lower average gas consumption by residential and commercial customers
year to date, which reduced natural gas purchases
-- Decreased fuel prices at Caribbean Utilities for the quarter
-- Decreased electricity sales at Caribbean Utilities for the quarter and
year to date and at FortisOntario year to date, which reduced fuel and
power purchases
Unfavourable
-- Increased fuel prices at Caribbean Utilities year to date and increased
purchased power costs at FortisBC Electric and FortisOntario for the
quarter and year to date
-- An increase in the base amount of energy supply costs expensed at
Maritime Electric in accordance with the operation of the Energy Cost
Adjustment Mechanism
-- Increased electricity sales at FortisBC Electric, Newfoundland Power,
Maritime Electric and Fortis Turks and Caicos for the quarter and year
to date and at FortisOntario for the quarter, which increased fuel and
power purchases
-- Approximately $1 million for the quarter and $3 million year to date
associated with unfavourable foreign currency translation
Factors Contributing to Quarterly and Year-to-Date
Operating Expenses Variances
Unfavourable
-- General inflationary and employee-related cost increases at the
Corporation's regulated utilities, and timing of certain expenses at
FortisBC Electric during 2012
-- Operating expenses associated with the Hilton Suites Hotel, which was
acquired in October 2011
Favourable
-- Reduced operating expenses at the FortisBC Energy companies during 2012,
mainly due to the accrual of non-asset retirement obligation ("non-ARO")
removal costs in depreciation, effective January 1, 2012, the timing of
certain expenditures during 2012 and lower customer care-related costs
as a result of insourcing the customer care function, effective January
1, 2012. Non-ARO removal costs were recorded in operating expenses in
2011.
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011, which decreased operating expenses year to date
Factors Contributing to Quarterly and Year-to-Date
Depreciation and Amortization Expense Variances
Unfavourable
-- Continued investment in energy infrastructure
-- Increased depreciation at the FortisBC Energy companies, mainly due to
the accrual of non-ARO removal costs in depreciation, effective January
1, 2012, as discussed above
Favourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011, which decreased depreciation year to date
-- Lower depreciation rates at FortisAlberta and FortisBC Electric,
effective January 1, 2012, as a result of the 2012 revenue requirements
decisions received in April 2012 and August 2012, respectively
Factors Contributing to Quarterly and Year-to-Date
Other Income (Expenses), Net Variances
Unfavourable
-- The favourable impact in 2011 of the $17 million (US$17.5 million) ($11
million after tax) fee paid to Fortis in July 2011 following the
termination of a Merger Agreement between Fortis and Central Vermont
Public Service Corporation ("CVPS")
-- Approximately $0.5 million ($0.5 million after tax) and $8.5 million
($7.5 million after tax) of costs incurred in the third quarter and
year-to-date 2012, respectively, related to the pending acquisition of
CH Energy Group
-- Foreign exchange losses of approximately $3 million and $2.5 million for
the third quarter and year-to-date 2012, respectively, associated with
the translation of the US dollar-denominated long-term other asset
representing the book value of the Corporation's expropriated investment
in Belize Electricity. A net foreign exchange gain of approximately $1.5
million ($2.5 million after tax) was recognized for the third quarter
and year-to-date 2011 related to the above item.
-- Lower capitalized equity component of allowance for funds used during
construction ("AFUDC"), mainly at the FortisBC Energy companies
-- An approximate $1 million gain on the sale of property at FortisAlberta
during the first quarter of 2011
Factors Contributing to Quarterly and Year-to-Date
Finance Charges Variances
Unfavourable
-- Higher long-term debt levels in support of the utilities' capital
expenditure programs
-- Lower capitalized debt component of AFUDC at the regulated utilities,
mainly at the FortisBC Energy companies
Favourable
-- Higher capitalized interest associated with the financing of the
construction of the Corporation's 51% controlling ownership interest in
the Waneta Expansion hydroelectric generating facility ("Waneta
Expansion")
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011, which decreased finance charges year to date
-- Lower short-term borrowings at the regulated utilities year to date,
driven by the FortisBC Energy companies
Factors Contributing to Quarterly and Year-to-Date
Income Taxes Variances
Favourable
-- Lower statutory corporate income tax rates and lower earnings before
income taxes
-- Differences in the deductions for income tax purposes compared to
accounting purposes period over period
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher corporate expenses, due to the favourable impact in 2011 of the
$11 million after-tax fee paid to Fortis in July 2011 following the
termination of a Merger Agreement between Fortis and CVPS, and a foreign
exchange loss of approximately $3 million after tax recognized in the
third quarter of 2012 compared to a net foreign exchange gain of
approximately $2.5 million after tax recognized in the third quarter of
2011
-- Decreased non-regulated hydroelectric production in Belize, due to lower
rainfall
-- A higher loss at the FortisBC Energy companies, largely related to the
unfavourable impact of the difference in the timing of the recognition
of revenue associated with seasonal gas consumption and certain
increased regulator-approved expenses in 2012, lower capitalized AFUDC
and lower-than-expected customer additions in 2012. The above items were
partially offset by higher gas transportation volumes to industrial
customers and the timing of certain operating and maintenance expenses
during 2012.
Favourable
-- Increased earnings at FortisAlberta, mainly due to higher net
transmission revenue, rate base growth and the timing of operating
expenses during 2012, partially offset by a lower allowed ROE
-- Increased earnings at FortisBC Electric, due to rate base growth, higher
pole-attachment revenue and lower-than-expected finance charges in 2012
-- Increased earnings at Newfoundland Power, mainly due to lower effective
income taxes and a higher allowed ROE, partially offset by the impact of
the support structure arrangements with Bell Aliant during 2011
Factors Contributing to Year-to-Date Earnings Variance
Unfavourable
-- Higher corporate expenses due to: (i) the favourable impact in 2011 of
the $11 million after-tax fee paid to Fortis in July 2011 following the
termination of a Merger Agreement between Fortis and CVPS; (ii)
approximately $7.5 million, after tax, of costs incurred year-to-date
2012 related to the pending acquisition of CH Energy Group; and (iii) a
foreign exchange loss of approximately $2.5 million after tax recognized
year-to-date 2012 compared to a net foreign exchange gain of
approximately $2.5 million after tax recognized year-to-date 2011. The
increase in corporate expenses was partially offset by lower finance
charges, primarily due to higher capitalized interest associated with
financing of the construction of the Corporation's 51% controlling
ownership interest in the Waneta Expansion.
Favourable
-- Increased earnings at FortisAlberta, due to rate base growth, higher net
transmission revenue, the timing of operating expenses during 2012,
lower effective income taxes and lower-than-expected finance charges,
partially offset by a lower allowed ROE and an approximate $1 million
gain on the sale of property during the first quarter of 2011
-- Increased earnings at Newfoundland Power, for the same reasons discussed
above for the quarter, in addition to increased electricity sales year
to date
-- Increased earnings at the FortisBC Energy companies, mainly due to rate
base growth, higher gas transportation volumes to industrial customers
and timing of certain operating and maintenance expenses during 2012,
partially offset by lower-than-expected customer additions in 2012,
lower capitalized AFUDC and the unfavourable impact of the difference in
the timing of recognition of revenue associated with seasonal gas
consumption and certain increased regulator-approved expenses in 2012
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
SEGMENTED RESULTS OF OPERATIONS
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy
Companies (6) (4) (2) 89 86 3
----------------------------------------------------------------------------
Regulated Electric
Utilities -
Canadian
FortisAlberta 26 19 7 73 58 15
FortisBC Electric 13 10 3 38 38 -
Newfoundland Power 9 8 1 28 24 4
Other Canadian Electric
Utilities 6 6 - 18 18 -
----------------------------------------------------------------------------
54 43 11 157 138 19
----------------------------------------------------------------------------
Regulated Electric
Utilities - Caribbean 7 6 1 16 16 -
Non-Regulated - Fortis
Generation 5 8 (3) 15 13 2
Non-Regulated - Fortis
Properties 8 9 (1) 17 18 (1)
Corporate and Other (23) (6) (17) (66) (42) (24)
----------------------------------------------------------------------------
Net Earnings Attributable
to Common Equity
Shareholders 45 56 (11) 228 229 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For a discussion of the nature of regulation and material
regulatory decisions and applications pertaining to the
Corporation's regulated utilities, refer to the "Regulatory
Highlights" section of this MD&A. A discussion of the financial
results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September
30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas Volumes (petajoules
("PJ")) 26 23 3 138 140 (2)
Revenue ($ millions) 192 197 (5) 1,004 1,090 (86)
(Loss) Earnings ($
millions) (6) (4) (2) 89 86 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver
Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI")
Factors Contributing to Quarterly Gas Volumes Variance
Favourable
-- Higher gas transportation volumes to industrial customers, due to
certain customers switching to natural gas from alternative sources of
fuel as a result of lower natural gas prices
Factors Contributing to Year-to-Date Gas Volumes Variance
Unfavourable
-- Lower average gas consumption by residential and commercial customers,
driven by overall warmer temperatures
Favourable
-- Higher gas transportation volumes to industrial customers, for the same
reason discussed above for the quarter
With the implementation of the new Customer Care Enhancement
Project on January 1, 2012, the FortisBC Energy companies changed
their definition of a customer. As a result of this change, the
FortisBC Energy companies adjusted their combined customer count
downwards by approximately 18,000, effective January 1, 2012. As at
September 30, 2012, the total number of customers served by the
FortisBC Energy companies was approximately 938,000.
The FortisBC Energy companies earn approximately the same margin
regardless of whether a customer contracts for the purchase and
delivery of natural gas or only for the delivery of natural gas. As
a result of the operation of regulator-approved deferral
mechanisms, changes in consumption levels and the commodity cost of
natural gas from those forecast to set residential and commercial
customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the
FortisBC Energy companies as a major portion of the gas distributed
is used for space heating. Most of the annual earnings of the
FortisBC Energy companies are realized in the first and fourth
quarters.
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Lower-than-expected customer additions in 2012
Favourable
-- A net increase in the delivery component of customer rates, effective
January 1, 2012, mainly due to ongoing investment in energy
infrastructure and forecasted certain higher expenses recoverable from
customers as reflected in the 2012-2013 revenue requirements decision
received in April 2012
-- Higher gas transportation volumes to industrial customers
Factors Contributing to Year-to-Date Revenue Variance
Unfavourable
-- The same factors discussed above for the quarter
-- Lower average gas consumption by residential and commercial customers
Favourable
-- The same factors discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- The difference in the timing of recognition of revenue and certain
expenses in 2012. Revenue is recognized based on seasonal gas
consumption while certain expenses are generally incurred evenly
throughout the year, which, combined with an approved increase in those
expenses in 2012, has resulted in timing differences contributing to
lower earnings quarter over quarter
-- Lower capitalized AFUDC, due to lower assets under construction period
over period
-- Lower-than-expected customer additions in 2012
Favourable
-- Higher gas transportation volumes to industrial customers
-- The timing of certain operating and maintenance expenses during 2012
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- The same factors discussed above for the quarter
Unfavourable
-- Lower-than-expected customer additions in 2012
-- Lower capitalized AFUDC, for the same reason discussed above for the
quarter
-- The difference in the timing of recognition of revenue and certain
expenses in 2012, for the reasons discussed above for the quarter, which
reduced earnings year to date compared to the same period last year
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries
(gigawatt hours
("GWh")) 4,099 3,911 188 12,434 12,135 299
Revenue ($ millions) 117 103 14 335 306 29
Earnings ($ millions) 26 19 7 73 58 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Energy Deliveries Variance
Favourable
-- Higher average consumption by oilfield and commercial customers, due to
increased activity mainly as a result of higher market prices for oil
-- Higher average consumption by residential customers, due to warmer
temperatures which increased air conditioning load
-- Growth in the number of customers, with the total number of customers
increasing by approximately 9,000 year over year as at September 30,
2012, driven by favourable economic conditions
-- Higher average consumption by farm and irrigation customers, due to
warmer temperatures and lower precipitation levels
Factors Contributing to Year-to-Date Energy Deliveries Variance
Favourable
-- Higher average consumption by oilfield and commercial customers, for the
same reason discussed above for the quarter
-- Growth in the number of customers, for the same reason discussed above
for the quarter
As a significant portion of FortisAlberta's distribution revenue
is derived from fixed or largely fixed billing determinants,
changes in quantities of energy delivered are not entirely
correlated with changes in revenue. Revenue is a function of
numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Quarterly Revenue Variance
Favourable
-- An increase in customer electricity distribution rates, effective
January 1, 2012, driven primarily by ongoing investment in energy
infrastructure and forecasted certain higher expenses recoverable from
customers
-- Net transmission revenue of approximately $3.5 million recognized for
the quarter and $6.5 million recognized year to date. In its April 2012
distribution revenue requirements decision, the regulator did not
approve the continuation of the deferral of transmission volume
variances associated with FortisAlberta's Alberta Electric System
Operator ("AESO") charges deferral account. In the absence of full
deferral, FortisAlberta is subject to volume risk on actual transmission
costs relative to those charged to customers based on forecast volumes
and price. Net transmission revenue is influenced by many factors, which
may result in actual transmission volumes varying from those forecasted.
-- Growth in the number of customers
-- An increase in franchise fee revenue of approximately $1 million for the
quarter and $3 million year to date
Unfavourable
-- A lower allowed ROE. The cumulative impact on revenue, from January 1,
2011, of the decrease in the allowed ROE to 8.75%, effective for both
2011 and 2012, from 9.00% for 2010 was recognized during the fourth
quarter of 2011, when the regulatory decision was received.
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The same factors discussed above for the quarter
Unfavourable
-- The recognition in the second quarter of 2011 of accrued revenue related
to the cumulative 2010 and year-to-date 2011 allowed debt return and
recovery of depreciation on the additional $22 million in capital
expenditures approved by the regulator to be included in rate base
associated with the Automated Metering Project, which had the impact of
reducing revenue by approximately $2 million period over period.
-- The same factor discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Net transmission revenue of approximately $3.5 million recognized for
the quarter and $6.5 million recognized year to date, as a result of the
distribution revenue requirements decision received in April 2012
-- Rate base growth, due to continued investment in energy infrastructure
-- The timing of operating expenses during 2012
Unfavourable
-- A lower allowed ROE, as discussed above
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors discussed above for the quarter
-- Lower effective income taxes, primarily due to additional loss
carryforwards being utilized in FortisAlberta's 2011 income tax return
filed in 2012, which decreased income tax expense in 2012, and higher
income taxes in 2011 related to the sale of property
-- Lower-than-expected finance charges in 2012
Unfavourable
-- The same factor discussed above for the quarter
-- An approximate $1 million gain on the sale of property during the first
quarter of 2011
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 728 713 15 2,313 2,300 13
Revenue ($ millions) 71 67 4 225 215 10
Earnings ($ millions) 13 10 3 38 38 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 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 electrical
utility assets owned by the City of Kelowna. Excludes the non-
regulated generation operations of FortisBC Inc.'s wholly owned
partnership, Walden Power Partnership
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption, due to differences in weather conditions
period over period
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- A net increase in customer electricity rates, effective January 1, 2012,
mainly due to ongoing investment in energy infrastructure and forecasted
certain higher expenses recoverable from customers as reflected in the
2012-2013 revenue requirements decision received in August 2012
-- A 1.4% increase in customer electricity rates, effective June 1, 2011,
as a result of the flow through to customers of increased purchased
power costs charged to FortisBC Electric by BC Hydro, which increased
revenue year to date
-- Higher pole-attachment revenue
-- Differences in the amount of PBR incentives refunded, and flow-through
adjustments owing, to customers period over period
-- The 2.1% and 0.6% increase in electricity sales for the quarter and year
to date, respectively
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Higher pole-attachment revenue
-- Lower-than-expected finance charges in 2012. As approved in the 2012-
2013 revenue requirements decision received in August 2012, variances
between actual finance charges and those forecasted in determining
customer electricity rates, beginning January 1, 2012, are no longer
permitted deferral account treatment and, therefore, favourably impacted
earnings in 2012
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors discussed above for the quarter
Unfavourable
-- The expiry of the PBR mechanism on December 31, 2011. Year-to-date 2011,
lower-than-expected costs, primarily purchased power costs, were shared
equally between customers and FortisBC Electric under the PBR mechanism.
Pursuant to the Company's 2012-2013 revenue requirements decision
received in August 2012, variances between actual electricity revenue
and purchased power costs and those used in determining customer
electricity rates are subject to full deferral account treatment and,
therefore, did not impact earnings year-to-date 2012.
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 940 923 17 4,113 4,026 87
Revenue ($ millions) 100 101 (1) 422 417 5
Earnings ($ millions) 9 8 1 28 24 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher concentration of electric-versus-oil heating in new home
construction combined with economic growth, which increased consumption
Unfavourable
-- Sunnier weather conditions, which reduced average consumption
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Revenue for 2011 included amounts related to support structure
arrangements, which were in place with Bell Aliant during 2011,
associated with the joint-use poles held for sale to Bell Aliant. The
joint-use poles were sold in October 2011.
Favourable
-- The 1.8% increase in electricity sales
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The 2.2% increase in electricity sales
Unfavourable
-- The impact of the support structure arrangements with Bell Aliant during
2011, as discussed above for the quarter
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Favourable
-- Lower effective income taxes, primarily due to lower Part VI.1 taxes,
including the favourable impact of reversals of statute-barred Part VI.1
taxes period over period, and a lower statutory income tax rate. For
further information on Part VI.1 tax, refer to the "Significant Items"
section of this MD&A.
-- A higher allowed ROE, effective January 1, 2012, which is being accrued
in 2012, as approved by the regulator, as a decrease in operating
expenses for deferred recovery from customers
-- Electricity sales growth year to date
Unfavourable
-- The impact of the support structure arrangements with Bell Aliant during
2011, as discussed above
-- Approximately $1 million in additional operating labour and maintenance
costs incurred as a result of Tropical Storm Leslie in September 2012
-- Higher depreciation expense, due to continued investment in energy
infrastructure
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 595 582 13 1,803 1,798 5
Revenue ($ millions) 91 87 4 264 256 8
Earnings ($ millions) 6 6 - 18 18 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Quarterly Electricity Sales Variance
Favourable
-- Higher average consumption by commercial customers in the agricultural
processing sector on Prince Edward Island ("PEI")
-- Higher average consumption by residential customers and several large
commercial customers in Ontario
Factors Contributing to Year-to-Date Electricity Sales Variance
Favourable
-- Higher average consumption by commercial customers in the agricultural
processing sector on PEI
-- Growth in the number of, and higher average consumption by, residential
customers on PEI and an increase in the number of such customers using
electricity for home heating
Unfavourable
-- Lower average consumption by residential and industrial customers in
Ontario, primarily during the first quarter of 2012, reflecting more
moderate temperatures and weak economic conditions in the region
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- The overall 2.2% and 0.3% increase in electricity sales for the quarter
and year to date, respectively, for the reasons discussed above
-- An increase in the basic component of customer rates at Maritime
Electric, effective March 1, 2012, associated with the higher flow
through and recovery of energy supply costs
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- Increased customer rates at FortisOntario
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Favourable
-- Lower operating expenses at FortisOntario for the quarter, largely due
to the timing of certain operating expenses during 2012
-- Electricity sales growth
-- Increased customer rates at FortisOntario
Unfavourable
-- Increased depreciation expense and finance charges at Maritime Electric,
due to continued investment in energy infrastructure and increased
short-term borrowings, respectively
-- Higher operating expenses at FortisOntario year to date, largely due to
an increase in employee-related costs and the timing of certain
operating expenses during 2012
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.00 0.98 0.02 1.00 0.98 0.02
----------------------------------------------------------------------------
Electricity Sales
(GWh) 197 197 - 547 744 (197)
Revenue ($ millions) 72 74 (2) 202 234 (32)
Earnings ($
millions) 7 6 1 16 16 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which
Fortis holds an approximate 60% controlling interest; three small
wholly owned utilities in the Turks and Caicos Islands, which include
Turks and Caicos Utilities Ltd., acquired in August 2012, FortisTCI
Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.
(collectively "Fortis Turks and Caicos"); and the financial results of
the Corporation's approximate 70% controlling interest in Belize
Electricity up to June 20, 2011. Effective June 20, 2011, the
Government of Belize expropriated the Corporation's investment in
Belize Electricity. As a result of no longer controlling the
operations of the utility, Fortis discontinued the consolidation
method of accounting for Belize Electricity, effective June 20, 2011.
For further information, refer to the "Significant Items" and
"Business Risk Management" sections of this MD&A.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar. The reporting currency of Belize Electricity
was the Belizean dollar, which is pegged to the US dollar at
BZ$2.00=US$1.00.
Factors Contributing to Quarterly Electricity Sales Variance
Favourable
-- Growth in the number of customers
-- Warmer temperatures experienced in the Turks and Caicos Islands, which
increased air conditioning load
-- Higher tourism activity in the Turks and Caicos Islands
-- Electricity sales in the Turks and Caicos Islands during the third
quarter of 2011 were reduced, due to the early and extended closure of a
certain hotel and other commercial customers resulting from a hurricane
Unfavourable
-- Higher rainfall experienced on Grand Cayman, which decreased air
conditioning load
Factors Contributing to Year-to-Date Electricity Sales Variance
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011. Excluding Belize Electricity, electricity sales decreased
approximately 0.5% year to date.
-- The same factor discussed above for the quarter
Favourable
-- The same factors discussed above for the quarter
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- The flow through in customer electricity rates of lower energy supply
costs at Caribbean Utilities, due to a decrease in the cost of fuel
period over period
-- Decreased electricity sales at Caribbean Utilities
-- The discontinuance of government subsidization of Fortis Turks and
Caicos' South Caicos operations, effective April 1, 2012, in accordance
with a rate decision received in February 2012
Favourable
-- Increased electricity sales at Fortis Turks and Caicos
-- An increase in electricity rates for Fortis Turks and Caicos' large
hotel customers, effective April 1, 2012, in accordance with a rate
decision received in February 2012
-- Approximately $1 million for the quarter and $5 million year to date of
favourable foreign exchange associated with the translation of US
dollar-denominated revenue, due to the strengthening of the US dollar
relative to the Canadian dollar period over period
-- An increase in base electricity rates at Caribbean Utilities, effective
June 1, 2012
Factors Contributing to Year-to-Date Revenue Variance
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for Belize Electricity,
effective June 20, 2011, which decreased revenue by approximately $45
million period over period
-- Decreased electricity sales at Caribbean Utilities
-- The discontinuance of government subsidization of Fortis Turks and
Caicos' South Caicos operations, as discussed above for the quarter
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
period over period
-- The same factors discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Lower finance charges at Caribbean Utilities
-- Increased electricity sales at Fortis Turks and Caicos
Unfavourable
-- Overall higher depreciation expense, and higher finance charges at
Fortis Turks and Caicos, largely due to investment in utility capital
assets
-- Decreased electricity sales at Caribbean Utilities
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more
fuel-efficient production realized with the commissioning of new
generation units at the utility
-- Lower operating expenses at Caribbean Utilities, driven by the timing of
capital projects
-- Increased electricity sales at Fortis Turks and Caicos
Unfavourable
-- Overall higher depreciation expense and finance charges, for the same
reason discussed above for the quarter
-- Increased operating expenses at Fortis Turks and Caicos, mainly
associated with the timing of capital projects
Fortis Turks and Caicos acquired TCU in August 2012 for an
aggregate purchase price of approximately $13 million (US$13
million), inclusive of debt assumed of $5 million (US$5 million).
For further information refer to the "Significant Items" section of
this MD&A.
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 81 111 (30) 256 277 (21)
Revenue ($ millions) 8 11 (3) 26 25 1
Earnings ($
millions) 5 8 (3) 15 13 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upstate
New York, with a combined generating capacity of 139 MW, mainly
hydroelectric
Factor Contributing to Quarterly Energy Sales Variance
Unfavourable
-- Decreased production in Belize and Upstate New York, due to lower
rainfall
Factors Contributing to Year-to-Date Energy Sales Variance
Unfavourable
-- Decreased production in Upstate New York, due to a generating facility
being out of service and lower rainfall
-- Decreased production in Ontario, due to lower rainfall
Favourable
-- Increased production in Belize, driven by higher rainfall during the
first half of 2012
Factor Contributing to Quarterly Revenue and Earnings Variances
Unfavourable
-- Decreased production in Belize
Factors Contributing to Year-to-Date Revenue and Earnings Variances
Favourable
-- Increased production in Belize
Unfavourable
-- Decreased production in Upstate New York
In May 2011 the generator at Moose River's hydroelectric
generating facility in Upstate New York sustained electrical
damage. Repairs to the generator were completed in the second
quarter of 2012 but another repair continues to keep the generating
facility offline. Revenue for the first half of 2012 reflected
insurance amounts received related to the loss of earnings during
the period in the first half of 2012 when the generator was being
repaired due to the electrical damage. The generating facility is
expected to be online by the end of 2012.
NON-REGULATED - FORTIS PROPERTIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended
September 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality -
Revenue per
Available Room
("RevPAR") ($) 94.04 94.83 (0.79) 82.09 80.54 1.55
Real Estate -
Occupancy Rate (as
at, %) (2) 91.8 94.2 (2.4) 91.8 94.2 (2.4)
----------------------------------------------------------------------------
Hospitality Revenue
($ millions) 48 47 1 130 123 7
Real Estate Revenue
($ millions) 17 16 1 51 50 1
----------------------------------------------------------------------------
Total Revenue ($
millions) 65 63 2 181 173 8
----------------------------------------------------------------------------
Earnings ($
millions) 8 9 (1) 17 18 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 23 hotels, collectively
representing more than 4,400 rooms, in eight Canadian provinces,
including the acquisition of the StationPark Hotel in London, Ontario,
which was acquired in October 2012 for approximately $13 million.
Fortis Properties also owns and operates approximately 2.7 million
square feet of commercial office and retail space primarily in
Atlantic Canada.
(2) Reduced occupancy rate is primarily due to increased vacancy in New
Brunswick.
Factors Contributing to Quarterly Revenue Variance
Favourable
-- Increased Hospitality Division revenue, driven by contribution from the
Hilton Suites Hotel, which was acquired in October 2011
Unfavourable
-- A 0.8% decrease in RevPar at the Hospitality Division. Excluding the
impact of the Hilton Suites Hotel, RevPAR was $93.20 for the third
quarter of 2012, a decrease of 1.7% quarter over quarter. The decrease
in RevPAR was due to an overall 2.0% decrease in hotel occupancy,
partially offset by an overall 0.3% increase in the average daily room
rate. Hotel occupancy in Atlantic Canada and central Canada decreased,
while occupancy in western Canada increased. The average daily room rate
increased in western Canada and central Canada, and decreased in
Atlantic Canada.
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- A 1.9% increase in RevPAR at the Hospitality Division, driven by
contribution from the Hilton Suites Hotel
-- Excluding the impact of the Hilton Suites Hotel, RevPAR was $80.80 year-
to-date 2012, an increase of 0.3% period over period. The increase in
RevPAR was due to an overall 1.7% increase in the average daily room
rate, partially offset by an overall 1.4% decrease in hotel occupancy.
The average daily room rate increased in all regions. Hotel occupancy in
Atlantic Canada and central Canada decreased, while occupancy in western
Canada increased.
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- Lower performance at the Hospitality Division, excluding the Hilton
Suites Hotel, primarily due to the impact of decreased occupancy at
hotel operations in Atlantic Canada and central Canada, and increased
depreciation due to capital additions and improvements
-- A $0.5 million gain on the sale of the Viking Mall during the first
quarter of 2011
Favourable
-- Contribution from the Hilton Suites Hotel
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 5 4 1 18 17 1
Operating Expenses 2 4 (2) 8 9 (1)
Depreciation and
Amortization - - - 1 1 -
Other Income
(Expenses), Net (3) 20 (23) (11) 20 (31)
Finance Charges 13 12 1 36 38 (2)
Income Tax
(Recovery) Expense (1) 3 (4) (6) (3) (3)
----------------------------------------------------------------------------
(12) 5 (17) (32) (8) (24)
Preference Share
Dividends 11 11 - 34 34 -
----------------------------------------------------------------------------
Net Corporate and
Other Expenses (23) (6) (17) (66) (42) (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
FortisBC Holdings Inc. ("FHI") corporate-related activities and the
financial results of FHI's wholly owned subsidiary FortisBC
Alternative Energy Services Inc. and FHI's 30% ownership interest in
CustomerWorks Limited Partnership ("CWLP"). The contracts between CWLP
and the FortisBC Energy companies ended on December 31, 2011.
Factors Contributing to Quarterly
Net Corporate and Other Expenses Variance
Unfavourable
-- Increased other expenses, net of other income, primarily due to: (i) the
favourable impact in 2011 of the $17 million (US$17.5 million) ($11
million after tax) fee paid to Fortis in July 2011 following the
termination of a Merger Agreement between Fortis and CVPS; (ii)
approximately $0.5 million ($0.5 million after tax) and $8.5 million
($7.5 million after tax) of costs incurred during the third quarter and
year-to-date 2012, respectively, related to the pending acquisition of
CH Energy Group; and (iii) foreign exchange losses of approximately $3
million and $2.5 million for the third quarter and year-to-date 2012,
respectively, associated with the translation of the US dollar-
denominated long-term other asset representing the book value of the
Corporation's expropriated investment in Belize Electricity. During the
third quarter of 2011, a foreign exchange gain of $7 million associated
with the translation of the above-noted US dollar-denominated long-term
other asset was partially offset by a $5.5 million ($4.5 million after
tax) foreign exchange loss associated with the translation of previously
hedged US dollar-denominated long-term debt. The favourable net impact
to earnings during the third quarter of 2011 of the above-noted foreign
exchange impacts was approximately $2.5 million.
-- Excluding income tax expense associated with the merger termination fee
paid to Fortis in July 2011, income tax recovery decreased, primarily
due to higher Part VI.1 taxes
Factors Contributing to Year-to-Date
Net Corporate and Other Expenses Variance
Unfavourable
-- The same factors discussed above for the quarter
Favourable
-- Lower finance charges, primarily due to higher capitalized interest
associated with the financing of the construction of the Corporation's
51% controlling ownership interest in the Waneta Expansion and the
impact of the conversion of the Corporation's US$40 million convertible
debentures into common shares in November 2011. The above decreases were
partially offset by higher interest on credit facility borrowings in
2012, due to higher average credit facility borrowings and higher fees
associated with the increase in the Corporation's committed revolving
credit facility to $1 billion in May 2012. During the third quarter of
2011, credit facility borrowings were repaid with a portion of the
proceeds from the common share offering in June and July 2011.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and
applications associated with each of the Corporation's regulated
gas and electric utilities year-to-date 2012 are summarized as
follows.
NATURE OF REGULATION
--------------------------------------------------------------------------
Allowed
Common
Regulated Regulatory Equity Supportive
Utility Authority (%) Allowed Returns (%) Features
-------------
Future or
Historical
Test Year
Used to Set
Customer
2010 2011 2012 Rates
--------------------------------------------------------------------------
ROE COS/ROE
-------------------------
FEI British 40 9.50 9.50 9.50 FEI: Prior to
Columbia January 1,
Utilities 2010, 50/50
Commission sharing of
("BCUC") earnings
above or
below
the allowed
ROE under a
PBR
mechanism
that expired
on
December 31,
2009 with a
two-year
phase-out
FEVI BCUC 40 10.00 10.00 10.00
FEWI BCUC 40 10.00 10.00 10.00 ROEs
established
by the BCUC
-------------
Future Test
Year
--------------------------------------------------------------------------
FortisBC BCUC 40 9.90 9.90 9.90 COS/ROE
Electric
PBR mechanism
for 2009
through
2011: 50/50
sharing of
earnings
above or
below the
allowed ROE
up
to an
achieved ROE
that is 200
basis
points above
or below the
allowed
ROE - excess
to deferral
account
ROE
established
by the BCUC
-------------
Future Test
Year
--------------------------------------------------------------------------
FortisAlberta AUC 41 9.00 8.75 8.75 COS/ROE
ROE
established
by the AUC
-------------
Future Test
Year
--------------------------------------------------------------------------
Newfoundland Newfoundland 45 9.00 +/-8.38 +/-8.80 +/- COS/ROE
Power and 50 bps 50 bps 50 bps
Labrador
Board of
Commissioners
of
Public
Utilities
("PUB")
The allowed
ROE had been
set using
an automatic
adjustment
formula tied
to long-term
Canada bond
yields. The
formula was
suspended for
2012.
Future Test
Year
--------------------------------------------------------------------------
Maritime Island 40 9.75 9.75 9.75 COS/ROE
Electric Regulatory
and Appeals
Commission
("IRAC")
-------------
Future Test
Year
--------------------------------------------------------------------------
FortisOntario Ontario Canadian
Energy Niagara Power
Board ("OEB") - COS/ROE
Canadian 40 8.01 8.01 8.01 (1) Algoma Power
Niagara - COS/ROE and
Power
subject to
Rural and
Remote Rate
Algoma Power 40 8.57 9.85 9.85 (1) Protection
("RRRP")
Program
Franchise Cornwall
Agreement Electric -
Cornwall Price cap
Electric with
commodity
cost flow
through
-------------
Canadian
Niagara Power
- 2009
historical
test year for
2010, 2011
and 2012
Algoma Power
- 2007
historical
test
year for
2010; 2011
test year for
2011
and 2012
--------------------------------------------------------------------------
ROA COS/ROA
-------------------------
Caribbean Electricity N/A 7.75 - 7.75 - 7.25 -
Utilities Regulatory 9.75 9.75 9.25 Rate-cap
Authority adjustment
("ERA") mechanism
based on
published
consumer
price indices
The Company
may apply for
a special
additional
rate to
customers in
the
event of a
disaster,
including a
hurricane.
-------------
Historical
Test Year
--------------------------------------------------------------------------
Fortis Turks Utilities N/A 17.50 17.50 17.50 COS/ROA
and Caicos make annual (2) (2) (2)
filings to
the Interim
Government of
the Turks and
Caicos Caicos
Islands
("Interim
Government")
If the actual
ROA is lower
than the
allowed ROA,
due to
additional
costs
resulting
from a
hurricane or
other event,
the Company
may apply for
an increase
in customer
rates in the
following
year.
-------------
Future Test
Year
--------------------------------------------------------------------------
(1) Based on the ROE automatic adjustment formula, the allowed ROE for
electric utilities in Ontario is 9.12% for utilities with rates
effective May 1, 2012. This ROE is not applicable to regulated
electric utilities in Ontario until they are scheduled to file their
next full COS rate applications. As a result, the allowed ROE of 9.12%
is not applicable to Canadian Niagara Power or Algoma Power for 2012.
(2) Amount provided under licence. ROA achieved in 2010 and 2011 was
significantly lower than the ROA allowed under the licence due to
significant investment occurring at the utility and the lack of rate
relief thereto.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
----------------------------------------------------------------------------
Regulated Utility Summary Description
----------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review with the BCUC natural gas
commodity prices and midstream costs 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 contracting for
midstream resources, such as third-party pipeline
and/or storage capacity. The commodity cost of
natural gas and midstream costs are flowed through
to customers without markup.
- Effective January 1, 2012, rates for typical
residential customers in the Lower Mainland
increased by approximately 3%, reflecting changes
in delivery and midstream costs. Interim approval
was also received to hold FEVI customer rates at
2011 levels, effective January 1, 2012. Natural
gas commodity rates were unchanged, effective
January 1, 2012.
- Effective April 1, 2012, due to a decrease in
natural gas commodity rates, rates for typical
residential customers in the Lower Mainland
decreased by approximately 10%, and rates for
residential customers at FEWI decreased
approximately 6%, following the BCUC's quarterly
review of commodity costs.
- Natural gas commodity rates were unchanged,
effective July 1, 2012, following the BCUC's
quarterly review of commodity costs.
- In July 2011 FEVI received a BCUC decision
approving the option for two First Nations bands
to invest up to a combined 15% in the equity
component of the capital structure of the
liquefied natural gas ("LNG") storage facility on
Vancouver Island. In late 2011 each band exercised
its option and each invested approximately $6
million in equity in the LNG storage facility on
January 1, 2012.
- In February 2012 the BCUC approved FEI's amended
application for a general tariff for the provision
of compressed natural gas ("CNG") and LNG for
transportation vehicles. FEI has filed
applications for and received interim rate
approval for two projects under the general
tariff. FEI has also applied for approval of its
LNG sales and dispensing service rate schedule on
a permanent basis. In October 2012 FEI received
approval for rate treatment of expenditures
incurred related to the provision of CNG and LNG
services, under the Greenhouse Gas Reductions
(Clean Energy) Regulation ("GHG Regulation") under
the Clean Energy Act.
- FEI is awaiting a decision from the BCUC on the
Alternative Energy Services Inquiry, which is a
proceeding to determine, among other things,
whether the provision of alternative energy
services is a regulated utility service and
whether FEI or an affiliate, i.e., FortisBC
Alternative Energy Services Inc. ("FAES"), should
provide these services. The alternative energy
services subject to the inquiry include providing
refuelling services for LNG-fuelled vehicles;
owning and operating district energy systems and
various forms of geo-exchange systems; and owning
facilities that upgrade raw biogas into biomethane
for the purpose of selling it to customers.
- In November 2011 FEI, FEVI and FEWI filed an
application with the BCUC for the amalgamation of
the three companies into one legal entity and for
the implementation of common rates and services
for the utilities' customers across British
Columbia, effective January 1, 2014. In late 2011
the utilities temporarily suspended their
application while they provided additional
information to the BCUC, as requested. In April
2012 the utilities refiled their application. The
amalgamation requires approval by the BCUC and
consent of the Government of British Columbia. The
evidence in the regulatory proceeding has closed
and a BCUC decision is pending.
- In November 2011 the BCUC issued preliminary
notification to public utilities subject to its
regulation, including the FortisBC gas and
electric utilities, that it would initiate a
Generic Cost of Capital ("GCOC") Proceeding in
early 2012. In February 2012 the BCUC established
that a GCOC Proceeding would take place and in
April 2012 issued a final scoping document
outlining the items that will be reviewed as part
of the GCOC Proceeding, which include: (i) the
appropriate cost of capital for a benchmark low-
risk utility, effective January 1, 2013, which
includes capital structure, ROE and interest on
debt; (ii) the establishment of a benchmark ROE
based on a benchmark low-risk utility effective
from January 1, 2013 through December 31, 2013 for
the initial transition year; (iii) the
determination of whether a return to an ROE
automatic adjustment mechanism is warranted, which
would be implemented January 1, 2014 or, if not, a
future regulatory process will be set to review
the ROE for a benchmark low-risk utility beyond
December 31, 2013; (iv) a generic methodology on
how to establish each utility's cost of capital in
reference to the cost of capital for a benchmark
low-risk utility; (v) a methodology to establish a
deemed capital structure and deemed cost of
capital, particularly for those utilities without
third-party debt; and (vi) for those utilities
that require a deemed interest rate, a methodology
to establish a deemed interest rate automatic
adjustment mechanism and, if not warranted, a
future regulatory process will be set on how the
deemed interest rate would be adjusted beyond
December 31, 2013. The GCOC Proceeding is not
intended to set each utility's risk premium. As
part of the GCOC Proceeding, the BCUC retained an
independent consultant to report on regulatory
practices in Canadian jurisdictions. The timetable
sets the evidence portion of the GCOC Proceeding
to take place through to early December 2012 with
an oral hearing to commence on December 12, 2012.
The result of the GCOC Proceeding could materially
impact the earnings of the FortisBC Energy
companies and FortisBC Electric.
- In April 2012 the BCUC issued its decision on
the FortisBC Energy companies' 2012-2013 Revenue
Requirements Application ("RRA"). The interim
increases in customer rates, effective January 1,
2012, at FEI and FEWI reflected the applied for
rate increases. The final approved increase in
customer delivery rates, effective January 1,
2012, was 4.2% at FEI, approximately 1.4% lower
than the interim customer delivery rates. The
final approved increase in customer delivery
rates, effective January 1, 2012, was 3.6% at
FEWI, approximately 1.4% lower than the interim
customer delivery rates. In its decision, the BCUC
approved FEVI's 2012 and 2013 customer rates to
remain unchanged from 2011 customer rates. The
difference between interim and final customer
rates at FEI and FEWI is being refunded to
customers, which commenced June 1, 2012. The final
approved customer delivery rates reflect allowed
ROEs and capital structure unchanged from 2011,
pending the outcome of the GCOC Proceeding as it
may impact 2013 rates. The cumulative impacts of
the 2012-2013 revenue requirements decision, where
such impacts were different from those estimated,
were recorded in the second quarter of 2012. The
final rate increases were driven by ongoing
investment in energy infrastructure focused on
system integrity and reliability, forecasted
increased operating expenses associated with
inflation, a heightened focus on safety and
security of the natural gas system, and increasing
compliance with codes and regulations.
- Following the announcement by the Government of
British Columbia of the GHG Regulation under the
Clean Energy Act, FEI announced an incentive
funding program to assist eligible vehicle
operators in purchasing LNG-fuelled vehicles. The
incentive program funding includes up to $62
million to offset a percentage of the incremental
capital cost for eligible operators in purchasing
qualifying LNG-fuelled vehicles. The eligible
applicants for the incentive program are
commercial return-to-base fleet operators of
heavy-duty trucks, buses, vocational vehicles and
marine vessels. Incentives are expected to be
awarded beginning in late 2012 and will cover up
to 80% of the eligible incremental capital costs
in the initial year. Additionally, the GHG
Regulation allows FEI to invest up to $30 million
for LNG fuelling stations and up to $12 million
for CNG fuelling stations. FEI has filed an
application with the BCUC for rate treatment of
the above expenditures under the GHG Regulation.
----------------------------------------------------------------------------
FortisBC Electric - In August 2012 the BCUC issued its decision on
FortisBC's 2012-2013 RRA, its 2012-2013 Capital
Expenditure Plan ("2012-2013 CEP") and its
Integrated System Plan ("ISP"). The ISP includes
the Company's Resource Plan, Long-Term Capital
Plan and Long-Term Demand Side Management Plan.
The resulting final revenue requirements for 2012
and 2013 reflect an allowed ROE and capital
structure unchanged from 2011, pending the outcome
of the GCOC Proceeding as it may impact 2013
rates. The decision includes an approved forecast
midyear rate base of approximately $1,112 million
for 2012 and $1,173 million for 2013. Under the
2012-2013 CEP, capital expenditures, before
customer contributions, of approximately $100
million for 2012 and approximately $120 million
for 2013, were approved by the BCUC. Approximately
$25 million of approved capital expenditures for
2012 are expected to be incurred in 2013, due to
the timing of receipt in 2012 of the BCUC
decision. The cumulative impacts of the 2012-2013
revenue requirements decision, where such impacts
were different from those estimated, were recorded
in the third quarter of 2012. In its decision the
BCUC approved deferral accounts and flow-through
treatment for variances between actual electricity
revenue and purchased power costs and those
forecasted in determining customer electricity
rates; however, flow-through treatment for finance
charges was denied. FortisBC Electric requested,
and the BCUC approved, that the interim refundable
1.5% increase in customer rates, effective January
1, 2012, as approved by the BCUC in November 2011,
be maintained for the remainder of 2012. The
difference between the final approved increase in
2012 customer rates of 0.6% and the interim
increase in customer rates of 1.5% has been
approved for deferral as a regulatory liability in
2012, to be used in 2013 to reduce the increase in
customer rates to 4.2%, effective January 1, 2013.
The rate increases are due to ongoing investment
in energy infrastructure, including increased
costs of financing the investment, as well as
increased purchased power costs.
- In November 2011 FortisBC Electric executed an
agreement to purchase capacity from the Waneta
Expansion and submitted the agreement to the BCUC.
The agreement allows FortisBC Electric to purchase
capacity over 40 years upon completion of the
Waneta Expansion, which is expected to be in
spring 2015. The form of the agreement was
originally accepted for filing by the BCUC in
September 2010. In May 2012 the BCUC determined
that the executed agreement is in the public
interest and a hearing is not required. The
agreement has been accepted for filing as an
energy supply contract and FortisBC Electric has
been directed by the BCUC to develop a rate-
smoothing proposal as part of a separate
submission or as part of FortisBC Electric's next
RRA.
- In March 2012 the BCUC issued an order
establishing a written hearing process to review
the prudency of approximately $29 million in
capital expenditures incurred related to the
Kettle Valley Distribution Source Project, which
was substantially completed in 2009. FortisBC
Electric believes that the capital expenditures
were prudently incurred and, therefore, cannot
reasonably determine if any of such expenditures
may be permanently disallowed from rate base and
any resulting financial impact. The written
hearing process is expected to continue through
the remainder of 2012.
- In July 2012 FortisBC Electric filed its
Advanced Metering Infrastructure ("AMI")
application, which is currently being reviewed by
the BCUC and various interveners. The AMI project
proposes to improve and modernize FortisBC
Electric's grid by exchanging its manually read
meters with advanced meters. The AMI project is
expected to cost approximately $48 million and be
completed in 2015.
----------------------------------------------------------------------------
FortisAlberta - In December 2011 the AUC issued its decision on
its 2011 GCOC Proceeding, establishing the allowed
ROE at 8.75% for 2011 and 2012 and, on an interim
basis, at 8.75% for 2013. The deemed equity
component of FortisAlberta's capital structure
remains at 41%. The AUC concluded that it would
not return to a formula-based ROE automatic
adjustment mechanism at that time and that it
would initiate a proceeding in due course to
establish a final allowed ROE for 2013 and revisit
the matter of a return to a formula-based approach
at a future proceeding. A GCOC Proceeding is
expected to commence late 2012 or early 2013.
- In March 2012 the AUC issued a bulletin
regarding maintaining regulated electricity rates.
The bulletin addressed the Government of Alberta's
letter requesting that regulated electricity rates
be maintained until the government responds to the
recommendations of the Retail Market Review
Committee ("Committee"), announced in February
2012. The Committee's mandate includes the review
of the default electricity rate charged to
customers who do not obtain retail service from a
retailer. The AUC will continue processing
applications and may approve applications that
maintain existing rates or propose rate
reductions; however, the AUC will not issue
decisions that result in rate increases. The
Committee's recommendations were provided to the
Alberta Minister for review in September 2012.
Further process has yet to be established and the
government-sanctioned rate freeze has not been
lifted.
- In January 2012 FortisAlberta and other
distribution utilities in Alberta filed motions
for leave to appeal with the Alberta Court of
Appeal with respect to the 2011 GCOC decision,
challenging certain pronouncements made by the AUC
as being incorrect regarding cost responsibility
for stranded assets. In June 2012 the AUC decided
that it would not permit a review and variance of
the 2011 GCOC decision which had been requested by
the utilities, but would examine the issue in a
future proceeding. The court process has been
temporarily adjourned pending the AUC's follow-up
proceeding.
- In April 2012 the AUC approved, substantially as
filed, a Negotiated Settlement Agreement ("NSA")
pertaining to FortisAlberta's 2012 distribution
revenue requirements, resulting in an average
increase in customer distribution rates of
approximately 5%, effective January 1, 2012,
consistent with the interim rate increase that was
previously approved by the AUC in December 2011.
The cumulative impacts of the 2012 revenue
requirements decision, where such impacts were
different from those estimated, were recorded in
the second quarter of 2012. The increase in
customer rates was driven primarily by ongoing
investment in energy infrastructure, including
increased financing costs. The NSA provided for
forecast midyear rate base of $2,025 million for
2012. The AUC did not approve the continuation of
the deferral of transmission volume variances
associated with FortisAlberta's AESO charges
deferral account for 2012. The deferral of
transmission volume variances, however, was
reinstated, effective January 1, 2013, per the
AUC's generic decision on its PBR Initiative ("PBR
Decision") as discussed further.
- In July 2012 the AUC issued a decision denying
an application made by the Central Alberta Rural
Electrification Association ("CAREA") in which
CAREA had requested, effective January 1, 2012,
that it be entitled to service any new customers
wishing to obtain electricity for use on property
overlapping CAREA's service area and that
FortisAlberta be restricted to providing service
in the overlapping CAREA service area to only
those customers who are not being provided service
by CAREA. The decision confirms that FortisAlberta
is the primary electricity distribution service
provider within its service territory, including
that portion of the Company's service territory
that overlaps with CAREA's service territory.
CAREA has not sought leave to appeal this
decision.
- In June 2012 AESO filed with the AUC a Customer
Contribution Policy Application and an Amortized
Construction Contribution Rider I Application. The
first application proposes a reduction in the
level of AESO contributions that transmission
customers, including FortisAlberta, would pay
versus what the transmission facility owner would
pay. The second application proposes that
transmission customers be given the option to make
the required AESO contributions as a series of
payments over a number of years, rather than as an
up-front payment. Effectively, this would result
in the transmission facility owner financing the
AESO contributions. Decisions on the applications
are not expected until 2013.
- In September 2012 the AUC issued a generic PBR
Decision outlying the PBR framework applicable to
distribution utilities in Alberta, including
FortisAlberta, for a five-year term commencing
January 1, 2013. Under PBR rate-making, a formula
is used to determine customer rates on an annual
basis. The implementation of PBR does not alter a
utility's right to a reasonable opportunity to
recover the prudent COS and the right to earn a
reasonable ROE. The formula approved by the AUC in
the PBR Decision raises concerns and uncertainty
for FortisAlberta regarding the treatment of
certain capital expenditures. The Company will be
seeking further clarification regarding those
capital expenditures in the required compliance
application, scheduled to be filed with the AUC in
November 2012. FortisAlberta has also sought leave
to appeal this issue with the Alberta Court of
Appeal.
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Newfoundland - In March 2012 Newfoundland Power filed a Cost of
Power Capital Application with the PUB to discontinue
the use of the current ROE automatic adjustment
mechanism and to approve a just and reasonable
rate of return on average rate base for 2012. In
June 2012 the PUB ordered that the allowed ROE for
2012 be increased to 8.80% from 8.38% for 2011.
The PUB also approved the deferred recovery from
customers of approximately $2.5 million before
tax, reflecting the difference between the 8.38%
allowed ROE currently reflected in customer
electricity rates in 2012 and the final approved
allowed ROE of 8.80%.
- In October 2012 the PUB approved Newfoundland
Power's 2013 Capital Expenditure Plan totalling
approximately $82 million, before customer
contributions.
- Effective July 1, 2012, the PUB approved an
overall average increase in Newfoundland Power's
customer electricity rates of 6.6%. The increase
in rates was primarily the result of the normal
annual operation of the Newfoundland and Labrador
Hydro ("Newfoundland Hydro") Rate Stabilization
Plan. Variances in the cost of fuel used to
generate electricity that Newfoundland Hydro sells
to Newfoundland Power are captured and flowed
through to customers through the operation of
Newfoundland Power's Rate Stabilization Account
("RSA"). The operation of the RSA further captures
variances in certain of Newfoundland Power's
costs, such as pension and energy supply costs.
The above-noted increase in customer rates does
not impact Newfoundland Power's earnings.
- In September 2012 Newfoundland Power filed a
General Rate Application for 2013 customer
electricity rates and cost of capital. A hearing
on the application is expected in the first
quarter of 2013.
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Maritime Electric - In February 2012 the PEI Energy Commission ("PEI
Commission") released its Discussion Paper,
Charting Our Electricity Future, which outlined
discussion points the PEI Commission is seeking
input through a consultative process with
stakeholders and the general public. These
discussion points included: (i) electricity
ownership and management on PEI and whether
Maritime Electric is doing a good job of balancing
safety and reliability with cost of service; (ii)
the future role of IRAC, the PEI Energy
Corporation and the PEI Office of Energy
Efficiency; (iii) a new cable interconnection;
(iv) the treatment of the financing of the $47
million of deferred incremental replacement energy
costs associated with the New Brunswick Power
Point Lepreau nuclear generating station; (v)
regional energy collaboration; (vi) demand side
management; (vii) renewable energy and
environmental stewardship; and (viii) potential
options for natural gas-generated electricity.
Public forums and stakeholder consultations
occurred in February and March 2012, in which
Maritime Electric was a participant. The PEI
Commission is expected to release a final report
of its recommendations to the Government of PEI
before the end of 2012.
- In March 2012 Maritime Electric received
regulatory approval to defer, for refund to
customers in a future period to be determined,
income tax expense reductions associated with the
Company's amendment of corporate income tax
filings for the years 2007 through 2010. The
amended filings seek to expense certain costs
previously capitalized for income tax purposes.
- In June 2012 Maritime Electric filed its 2013
Capital Budget Application totaling approximately
$26 million, before customer contributions.
- Maritime Electric intends to file an application
for 2013 customer rates and allowed ROE with IRAC.
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FortisOntario - In non-rebasing years, customer electricity
distribution rates are set using inflationary
factors less an efficiency target under the Third-
Generation Incentive Rate Mechanism ("IRM") as
prescribed by the OEB. In the first quarter of
2012, the OEB published applicable inflationary
and efficiency targets, resulting in minimal
changes in base customer electricity distribution
rates at FortisOntario's operations in Fort Erie,
Gananoque and Port Colborne effective May 1, 2012.
The Third-Generation IRM maintains the allowed ROE
at 8.01% for 2012.
- In April 2012 the OEB issued Final Decisions and
Orders for customer rates effective May 1, 2012 at
FortisOntario's operations in Fort Erie, Gananoque
and Port Colborne. The result was an average 3.1%
decrease in residential customer rates in Fort
Erie, an average 0.6% increase in residential
customer rates in Gananoque and an average 4.6%
decrease in residential customer rates in Port
Colborne. The above-noted rate changes were mainly
due to changes in rate riders associated with
regulatory deferral accounts and smart meter
funding.
- In April 2011 FortisOntario provided the City of
Port Colborne and Port Colborne Hydro with an
irrevocable written notice of FortisOntario's
election to exercise the purchase option, under
the then-current operating lease agreement, at the
purchase option price of approximately $7 million
on April 15, 2012. The purchase constituted the
sale of the remaining assets of Port Colborne
Hydro to FortisOntario. The purchase transaction
was approved by the OEB in March 2012 and closed
on April 16, 2012.
- In March 2012 the OEB issued its decision on
Algoma Power's Third-Generation IRM application
for customer electricity distribution rates,
effective January 1, 2012. The decision approved a
price-cap index of 2.81% for customers subject to
RRRP funding and 0.38% for those customers not
subject to RRRP funding. RRRP funding for 2012 has
been set at approximately $11 million. Algoma
Power's allowed ROE is maintained at 9.85% for
2012.
- In May 2012 FortisOntario filed a COS
Application for electricity distribution rates in
Fort Erie, Port Colborne and Gananoque, effective
January 1, 2013, using a 2013 forward test year.
The application proposes an allowed ROE of 9.12%
on a deemed equity component of capital structure
of 40%. The allowed ROE is subject to change based
on operation of the automatic ROE adjustment
formula. In September 2012 a settlement agreement
on the COS Application was reached on all issues,
except for the disposal of an income tax-related
regulatory deferral account of $1 million, which
is expected to be decided upon by the OEB by the
end of 2012.
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Caribbean Utilities - In April 2012 the ERA approved Caribbean
Utilities' 2012-2016 Capital Investment Plan
("CIP") for US$122 million of non-generation
installation capital expenditures. The remaining
US$62 million of the 2012-2016 CIP relates to new
generation installation, which is subject to a
competitive solicitation process with the next
generation unit scheduled for installation in
2014. The 2012-2016 CIP was prepared in line with
the Certificate of Need that was filed with the
ERA in November 2011. Proposals for installation
of the new generation unit from six qualified
bidders, including Caribbean Utilities, was
requested by the ERA and Caribbean Utilities'
proposal was submitted in July 2012. The ERA's
decision on the successful bidder is expected by
the end of the 2012. A second increment of 18 MW
of new generating capacity is required up to three
years later in 2017, contingent on economic growth
on Grand Cayman and the related growth in demand
for electricity.
- The proposed 2013-2017 CIP, totalling
approximately US$125 million of non-generation
installation capital expenditures, was submitted
to the ERA in October 2012 for approval.
- In March 2012 the ERA approved the creation of
Caribbean Utilities' wholly owned subsidiary
DataLink Ltd. ("DataLink"). Subsequently, the
Information and Communications Technology
Authority ("ICTA") granted a licence to DataLink
to provide fibre optic infrastructure and other
information and communication technology services
on Grand Cayman. The ICTA licence allows DataLink
to assume full responsibility for existing pole-
attachment agreements and optical fibre lease
agreement currently held by Caribbean Utilities
with third-party information and communications
technology service providers. The reassignment of
existing contracts is in progress and is expected
to be completed before the end of 2012. The ERA
has approved executed management and maintenance,
pole attachment and fibre optic agreements between
Caribbean Utilities and DataLink.
- In December 2011 Caribbean Utilities conducted
and completed a competitive bidding process to
fill up to 13 MW of non-firm renewable energy
capacity. During the third quarter of 2012,
Caribbean Utilities commenced discussions with two
renewable energy developers that were selected to
provide renewable energy to the utility's grid.
The proposals being considered are two 5-MW solar
photovoltaic power plants and one 3-MW small-scale
wind turbine project. The developers will finance,
construct, own and operate the renewable
generation facilities. Negotiations towards firm
power purchase agreements with the developers are
ongoing. The power purchase agreements, however,
are subject to ERA review and approval. Once the
negotiations are completed, and the necessary
regulatory approvals received, final power
purchase agreements will be established with the
two developers who will then start construction of
the projects. It is anticipated that the 13 MW of
renewable energy capacity will be connected to the
grid by 2014.
- Effective June 1, 2012, following review and
approval by the ERA, Caribbean Utilities' base
customer electricity rates increased by 0.7% as a
result of changes in the applicable consumer price
indices and the utility's achieved ROA for 2011.
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Fortis Turks and Caicos - An independent review of the regulatory
framework for the electricity sector in the Turks
and Caicos Islands was performed during the third
quarter of 2011 on behalf of the Interim
Government. Fortis Turks and Caicos provided a
comprehensive response to the Interim Government
in January 2012 stating that the Company supports
limited mutually agreed upon reforms, but that its
current licences must be respected and can only be
changed by mutual consent. Specifically, Fortis
Turks and Caicos would support reforms that
strengthen the role of the regulator in the rate-
setting process and that are fair to all
stakeholders. Negotiations between Fortis Turks
and Caicos and the Interim Government commenced
during the third quarter of 2012 with Fortis Turks
and Caicos presenting a new regulatory framework
proposal to the Interim Government. A third-party
consultant was engaged by the Interim Government
to review the proposal and provide
recommendations.
- In February 2012 the Interim Government approved
an approximate 26% increase in electricity rates,
effective April 1, 2012, for Fortis Turks and
Caicos' large hotel customers. In addition, other
qualitative enhancements to the franchise were
also achieved, including: (i) improved wording in
the Electricity Rate Regulation; (ii) an approved
increase in kilowatt hour consumption thresholds
for both medium and large hotels; (iii) an
expansion of service territory to cover all of the
Caicos Islands, except for areas currently
serviced by private suppliers' licences, with new
25-year licences issued for the expanded service
territory; and (iv) the discontinuance of the
government subsidization of the utility's South
Caicos operations.
- In March 2012 Fortis Turks and Caicos submitted
its 2011 annual regulatory filing outlining the
Company's performance in 2011. Included in the
filing were the calculations, in accordance with
the utility's licence, of rate base of US$166
million for 2011 and cumulative shortfall in
achieving allowable profits of US$72 million as at
December 31, 2011.
- In April 2012 Fortis Turks and Caicos entered
into a Streetlight Takeover Agreement with the
Interim Government, whereby the responsibility for
the ownership, installation and maintenance of all
streetlights in the utility's service territory
was transferred to Fortis Turks and Caicos.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the
consolidated balance sheets between September 30, 2012 and December
31, 2011.
Significant Changes in the Consolidated Balance Sheets
(Unaudited) between September 30, 2012 and December 31, 2011
----------------------------------------------------------------------------
Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
----------------------------------------------------------------------------
Cash and cash 60 The increase was primarily due to cash on
equivalents hand at the FortisBC Energy companies
associated with seasonality of operations and
a portion of the proceeds received from an
equity injection by Fortis during the second
quarter of 2012, and the timing of cash
payments at FortisAlberta and the Waneta
Expansion Limited Partnership (the "Waneta
Partnership").
----------------------------------------------------------------------------
Accounts (228) The decrease was driven by the FortisBC
receivable Energy companies, mainly due to a seasonal
decrease in sales and the lower commodity
cost of natural gas reflected in customer
rates. Accounts receivable also decreased at
Newfoundland Power, due to seasonality and
the timing of collections from customers and
decreased at FortisAlberta, due to decreased
rate riders and a change in the billing of
retailers from a monthly to a weekly basis.
----------------------------------------------------------------------------
Inventories 23 The increase was driven by the normal
seasonal increase of gas in storage at the
FortisBC Energy companies, partially offset
by the impact of lower natural gas commodity
prices.
----------------------------------------------------------------------------
Regulatory (28) The decrease was mainly due to: (i)
assets - approximately $100 million associated with
current and the deferral of the change in the fair market
long-term value of the natural gas derivatives at the
FortisBC Energy companies; (ii) the
collection of approximately $44 million in
AESO charges deferral at FortisAlberta; and
(iii) a reduction in regulatory deferred
employee future benefits costs. The decrease
was partially offset by higher regulatory
deferred income taxes, and an increase in the
deferral of various other costs, as permitted
by the regulators, mainly at the FortisBC
regulated utilities.
----------------------------------------------------------------------------
Other assets 25 The increase was mainly due to financing
costs associated with the Corporation's
Subscription Receipts offering, an increase
in income taxes receivable at Maritime
Electric and an increase in defined benefit
pension assets at Newfoundland Power.
----------------------------------------------------------------------------
Utility capital 406 The increase primarily related to $737
assets million invested in electricity and gas
systems, partially offset by depreciation and
customer contributions year-to-date 2012, and
the impact of foreign exchange on the
translation of US-dollar denominated utility
capital assets.
----------------------------------------------------------------------------
Short-term (62) The decrease was primarily due to a reduction
borrowings in borrowings at the FortisBC Energy
companies with a portion of the proceeds
received from an equity injection by Fortis
during the second quarter of 2012 and
seasonality of operations, partially offset
by increased borrowings at Caribbean
Utilities, mainly to repay maturing long-term
debt.
----------------------------------------------------------------------------
Accounts (135) The decrease was mainly due to: (i) the $75
payable and million change in the fair market value of
other current the natural gas derivatives at the FortisBC
liabilities Energy companies; (ii) lower amounts owing
for purchased natural gas at the FortisBC
Energy companies and purchased power at
Newfoundland Power, associated with
seasonality of operations; (iii) the timing
of payment of property taxes and franchise
fees at the FortisBC Energy companies; and
(iv) lower accounts payable at the Waneta
Partnership associated with the timing of
payments related to the construction of the
Waneta Expansion. The decrease was partially
offset by higher accounts payable associated
with transmission-connected projects and
timing of AESO payments for transmission
costs at FortisAlberta.
----------------------------------------------------------------------------
Regulatory 65 The increase was mainly due to an overall
liabilities - increase in deferrals at the FortisBC Energy
current and companies and an increase in the AESO charges
long-term deferral at FortisAlberta. The increase in
deferrals at the FortisBC Energy companies
was mainly due to: (i) an increase in the
Revenue Surplus Deferred Account, reflecting
amounts collected in customer rates in excess
of the cost of providing service at FEVI
year-to-date 2012; (ii) an increase in the
Midstream Cost Reconciliation Account and the
Commodity Cost Reconciliation Account, as
amounts collected in customer rates were in
excess of actual midstream and commodity gas-
delivery costs, respectively, year-to-date
2012; and (iii) the provisioning for non-ARO
removal costs commencing January 1, 2012. The
increase was partially offset by
approximately $25 million associated with the
deferral of the change in the fair market
value of the natural gas derivatives at the
FortisBC Energy companies.
----------------------------------------------------------------------------
Deferred income 57 The increase was driven by tax timing
tax liabilities differences related mainly to capital
- current and expenditures at the regulated utilities.
long-term
----------------------------------------------------------------------------
Long-term debt 149 The increase was primarily due to higher
(including borrowings under the Corporation's committed
current credit facility, largely in support of the
portion) construction of the Waneta Expansion and for
other general corporate purposes. The
increase was partially offset by regularly
scheduled debt repayments at Fortis
Properties, the FortisBC Energy companies and
Caribbean Utilities, and the impact of
foreign exchange on the translation of US-
dollar denominated debt.
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Shareholders' 110 The increase was primarily due to net
equity earnings attributable to common equity
(before non- shareholders year-to-date 2012, less common
controlling share dividends, and the issuance of common
interests) shares mainly under the Corporation's
dividend reinvestment and stock option plans.
----------------------------------------------------------------------------
Non-controlling 80 The increase was driven by advances from the
interests 49% non-controlling interests in the Waneta
Partnership and an approximate $12 million,
or 15%, equity investment by two First
Nations bands in the LNG storage facility on
Vancouver Island.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources
and uses of cash for the third quarter and year-to-date 2012, as
compared to the same periods in 2011, followed by a discussion of
the nature of the variances in cash flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of
Period 231 296 (65) 87 107 (20)
Cash Provided by
(Used in):
Operating
Activities 221 151 70 804 684 120
Investing
Activities (277) (265) (12) (761) (748) (13)
Financing
Activities (28) (77) 49 17 62 (45)
Effect of Exchange
Rate Changes on
Cash and Cash
Equivalents - 1 (1) - 1 (1)
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Cash, End of Period 147 106 41 147 106 41
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Operating Activities: Cash flow from operating activities was
$70 million higher quarter over quarter. The increase was primarily
due to: (i) favourable changes in working capital; (ii) the
collection from customers of regulator-approved increased
depreciation and amortization expense, mainly at the FortisBC
Energy companies; and (iii) favourable changes in long-term
regulatory deferral accounts. The favourable changes in working
capital were associated with changes in inventories, accounts
payable and other current liabilities, and current regulatory
deferral accounts, partially offset by unfavourable changes in
accounts receivable. The increase was partially offset by lower
earnings.
Cash flow from operating activities was $120 million higher year
to date compared to the same period last year. The increase was
primarily due to favourable changes in working capital and the
collection from customers of regulator-approved increased
depreciation and amortization expense, mainly at the FortisBC
Energy companies. Favourable changes in working capital were
associated with changes in current regulatory deferral accounts and
accounts receivable. The above increase was partially offset by
unfavourable changes in long-term regulatory deferral accounts and
a defined benefit pension solvency deficit funding payment made by
Newfoundland Power during the second quarter of 2012.
Investing Activities: Cash used in investing activities was $12
million higher for the quarter and $13 million higher year to date.
The increases reflected the acquisition of TCU in August 2012 for a
net cash purchase price of approximately $7 million (US$7 million),
net of cash acquired. The increase year to date also reflected the
acquisition of the remaining assets of Port Colborne Hydro by
FortisOntario in April 2012 for approximately $7 million.
For the quarter, lower capital spending related to the
non-regulated Waneta Expansion and at FortisBC Electric and the
Caribbean Regulated Electric Utilities was largely offset by an
increase in capital spending at FortisAlberta. Year to date, lower
capital spending at the FortisBC Energy companies and FortisBC
Electric was largely offset by an increase in capital spending at
FortisAlberta and capital spending related to the non-regulated
Waneta Expansion. Capital expenditures for the first half of 2011
included those of Belize Electricity up to June 20, 2011, when the
utility was expropriated by the GOB.
Financing Activities: Cash used in financing activities was $49
million lower quarter over quarter. The decrease was primarily due
to lower net repayments under committed credit facilities
classified as long term, partially offset by lower net proceeds
from short-term borrowings and lower proceeds from the issuance of
common shares.
Cash provided by financing activities was $45 million lower year
to date compared to the same period last year. The decrease was
primarily due to: (i) lower proceeds from the issuance of common
shares; (ii) lower proceeds from long-term debt; (iii) higher
repayments of long-term debt; (iv) higher common share dividends
paid; and (v) issue costs related to the June 2012 Subscription
Receipts offering. The decrease was partially offset by higher net
borrowings under committed credit facilities classified as long
term and lower net repayments of short-term borrowings.
Net proceeds from short-term borrowings were $69 million lower
quarter over quarter, driven by the FortisBC Energy companies. Net
repayments of short-term borrowings were $53 million lower year to
date compared to same period last year, driven by Caribbean
Utilities.
Proceeds from long-term debt, net of issue costs, repayments of
long-term debt and capital lease and finance obligations, and net
(repayments) borrowings under committed credit facilities for the
quarter and year to date compared to the same periods last year are
summarized in the following tables.
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caribbean Utilities
(1) - 9 (9) - 38 (38)
Other - - - - 1 (1)
----------------------------------------------------------------------------
Total - 9 (9) - 39 (39)
----------------------------------------------------------------------------
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(1) Issued 15-year US$15 million 4.85% and 20-year US$25 million 5.10%
unsecured notes. The first tranche of US$30 million was issued in June
2011 and the second tranche of US$10 million was issued in July 2011.
The net proceeds were used to repay current installments on long-term
debt and short-term credit facility borrowings and to finance capital
expenditures.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
(Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy
Companies - (1) 1 (18) (3) (15)
Caribbean Utilities - - - (13) (12) (1)
Fortis Properties - (2) 2 (24) (6) (18)
Other - - - (2) (6) 4
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Total - (3) 3 (57) (27) (30)
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----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta (22) 33 (55) (13) 50 (63)
FortisBC Electric (17) (7) (10) (9) - (9)
Newfoundland Power (20) (13) (7) 8 10 (2)
Corporate 50 (191) 241 235 (165) 400
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Total (9) (178) 169 221 (105) 326
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Borrowings under credit facilities by the utilities are
primarily in support of their capital expenditure programs and/or
for working capital requirements. Repayments are primarily financed
through the issuance of long-term debt, cash from operations and/or
equity injections from Fortis. From time to time, proceeds from
preference share, common share and long-term debt offerings are
used to repay borrowings under the Corporation's committed credit
facility. The borrowings under the Corporation's committed credit
facility during 2012 were largely in support of the construction of
the Waneta Expansion and for other general corporate purposes.
Advances of approximately $14 million for the quarter and $70
million year to date were received from non-controlling interests
in the Waneta Partnership to finance capital spending related to
the Waneta Expansion, compared to $20 million received for the
third quarter of 2011 and $76 million received year-to-date 2011.
In January 2012 advances of approximately $12 million were received
from two First Nations bands representing their 15% equity
investment in the LNG storage facility on Vancouver Island.
In June 2011 Fortis publicly issued 9.1 million common shares
for gross proceeds of $300 million. In July 2011 an additional 1.2
million common shares were publicly issued upon the exercise of an
over-allotment option, resulting in gross proceeds of approximately
$41 million. The total net proceeds of $327 million from the common
share offering were used to repay borrowings under credit
facilities and finance equity injections into the regulated
utilities in western Canada and the Waneta Partnership in support
of infrastructure investment, and for other general corporate
purposes.
Common share dividends paid during the third quarter of 2012
were $42 million, net of $15 million of dividends reinvested,
compared to $38 million, net of $16 million of dividends
reinvested, paid during the same quarter of 2011. Common share
dividends paid year-to-date 2012 were $128 million, net of $43
million of dividends reinvested, compared to $109 million, net of
$47 million of dividends reinvested, paid year-to-date 2011. The
dividend paid per common share for each of the first, second and
third quarters of 2012 was $0.30 compared to $0.29 for each of the
first, second and third quarters of 2011. The weighted average
number of common shares outstanding for the third quarter and year
to date was 190.2 million and 189.6 million, respectively, compared
to 186.5 million and 179.5 million for the third quarter and year
to date, respectively, in 2011.
CONTRACTUAL OBLIGATIONS
As at September 30, 2012, consolidated contractual obligations
of Fortis over the next five years and for periods thereafter are
outlined in the following table. A detailed description of the
nature of the obligations is provided in the 2011 Annual MD&A
and below, where applicable. The presentation of certain
contractual obligations has changed from that provided in the 2011
Annual MD&A, due to the adoption of US GAAP. For further
information concerning these changes, refer to the 2011 audited
consolidated financial statements prepared in accordance with US
GAAP and voluntarily filed on SEDAR.
----------------------------------------------------------------------------
Contractual Obligations (Unaudited) Due Due in Due in Due
As at September 30, 2012 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 5,937 90 826 563 4,458
Capital lease and finance
obligations (1) 2,605 47 97 101 2,360
Waneta Partnership promissory note 72 - - - 72
Gas purchase contract obligations
(2) 351 289 62 - -
Power purchase obligations
FortisBC Electric 20 11 6 3 -
FortisOntario 371 44 99 105 123
Maritime Electric 148 37 80 18 13
Capital cost 446 17 36 35 358
Joint-use asset and shared service
agreements 63 4 8 6 45
Operating lease obligations 26 4 7 6 9
Defined benefit pension funding
contributions (3) 88 37 34 15 2
Other 8 1 3 - 4
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Total 10,135 581 1,258 852 7,444
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(1) Includes principal payments, imputed interest and executory costs,
mainly related to FortisBC Electric's Brilliant Power Purchase
Agreement and Brilliant Terminal Station
(2) Based on index prices as at September 30, 2012
(3) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than these estimated amounts, pending completion of the next
actuarial valuations for funding purposes, which are expected to be
performed as of the following dates for the larger defined benefit
pension plans:
December 31, 2012 FortisBC Energy companies (covering non-unionized
employees)
December 31, 2013 FortisBC Energy companies (covering unionized
employees)
December 31, 2013 FortisBC Electric
December 31, 2013 FortisAlberta
December 31, 2014 Newfoundland Power
The estimate of defined benefit pension funding contributions includes
the impact of the outcome of the December 31, 2011 actuarial
valuation, completed in April 2012, associated with the defined
benefit pension plan at Newfoundland Power. As a result of the
valuation, Newfoundland Power is required to fund a solvency
deficiency of approximately $53 million, including interest, over five
years beginning in 2012, which is reflected in the above table. The
Company fulfilled its 2012 annual solvency deficit funding requirement
during the second quarter of 2012.
Other contractual obligations, which are not reflected in the
above table, did not materially change from those disclosed in the
2011 Annual MD&A, except as described as follows.
In January 2012 two First Nations bands each invested
approximately $6 million in equity in the Mount Hayes LNG storage
facility, representing a 15% equity interest in the Mount Hayes
Limited Partnership, with FEVI holding the controlling 85%
ownership interest. The non-controlling interests hold put options,
which, if exercised, would require FEVI to repurchase the 15%
ownership interest for cash, in accordance with the terms of the
partnership agreement.
In September 2012 Caribbean Utilities entered into primary and
secondary fuel supply contracts with two different suppliers and is
committed to purchasing approximately 60% and 40% of the Company's
diesel fuel requirements under each of the contracts, respectively,
for the operation of Caribbean Utilities' diesel-powered generating
plant. The approximate combined quantities under the contracts,
expressed in millions of imperial gallons, on an annual basis by
fiscal year are: 2012 - 10.8, 2013 - 32.4 and 2014 - 18.9. The
contracts expire in July 2014 with the option to renew for two
additional 18-month terms. The renewal options can be exercised
only within six months of the expiry dates of the existing
contracts.
In February 2012 Fortis entered into an agreement to acquire CH
Energy Group for US$1.5 billion, including the assumption of
approximately US$500 million in debt on closing. The acquisition is
expected to close by the end of the first quarter of 2013. In June
2012, to finance a portion of the purchase price of CH Energy
Group, Fortis sold 18,500,000 Subscription Receipts at $32.50 each,
realizing gross proceeds of approximately $601 million. Each
Subscription Receipt will entitle the holder thereof to receive, on
satisfaction of the Release Conditions and without payment of
additional consideration, one common share of Fortis and a cash
payment equal to the dividends declared on Fortis common shares to
holders of record during the period from June 27, 2012 to the date
of issuance of the common shares in respect of the Subscription
Receipts. For further information on the pending acquisition of CH
Energy Group and the Subscription Receipts offering, refer to the
"Significant Items" and "Business Risk Management" sections of this
MD&A.
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets for approximately $55 million. Closing of
the transaction is subject to certain conditions and approvals. For
further information, refer to the "Significant Items" section of
this MD&A.
For a discussion of the nature and amount of the Corporation's
consolidated capital expenditure program, which is not included in
the preceeding Contractual Obligations table, refer to the "Capital
Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and
electricity distribution require ongoing access to capital to
enable the utilities to fund maintenance and expansion of
infrastructure. Fortis raises debt at the subsidiary level to
ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of
acquisitions at the corporate level with proceeds from common
share, preference share and long-term debt offerings. To help
ensure access to capital, the Corporation targets a consolidated
long-term capital structure containing approximately 40% equity,
including preference shares, and 60% debt, as well as
investment-grade credit ratings. Each of the Corporation's
regulated utilities maintains its own capital structure in line
with the deemed capital structure reflected in each of the
utility's customer rates.
The consolidated capital structure of Fortis is presented in the
following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
September 30, 2012 December 31, 2011
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
and finance obligations
(net of cash) (1) (2) 6,328 56.6 6,296 57.1
Preference shares 912 8.2 912 8.3
Common shareholders' equity 3,933 35.2 3,823 34.6
----------------------------------------------------------------------------
Total (3) 11,173 100.0 11,031 100.0
----------------------------------------------------------------------------
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(1) Includes long-term debt and capital lease and finance obligations,
including current portion, and short-term borrowings, net of cash
(2) Excluding capital lease and finance obligations, the debt component of
the capital structure was 54.9% as at September 30, 2012 and 55.3% as
at December 31, 2011.
(3) Excludes amounts related to non-controlling interests
The improvement in the capital structure was primarily due to:
(i) lower short-term borrowings; (ii) an increase in cash; (iii)
common shares issued, mainly under the Corporation's dividend
reinvestment and stock option plans; and (iv) net earnings
attributable to common equity shareholders, net of dividends. The
capital structure was also impacted by an increase in long-term
debt, mainly due to higher borrowings under the Corporation's
committed credit facility, largely in support of the construction
of the Waneta Expansion and for other general corporate purposes,
partially offset by regularly scheduled debt repayments.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
In May 2012 and July 2012, S&P and DBRS, respectively,
affirmed the Corporation's debt credit ratings. Due to the
Corporation's financing plans for the pending acquisition of CH
Energy Group and the expected completion of the Waneta Expansion on
time and on budget, S&P and DBRS also removed the ratings from
credit watch with negative implications and under review with
developing implications, respectively, where the ratings had been
placed in February 2012.
The above-noted credit ratings reflect the Corporation's low
business-risk profile and diversity of its operations, the
stand-alone nature and financial separation of each of the
regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the
Corporation's reasonable credit metrics and its demonstrated
ability and continued focus on acquiring and integrating stable
regulated utility businesses financed on a conservative basis.
CAPITAL EXPENDITURE PROGRAM
Capital investment in infrastructure is required to ensure
continued and enhanced performance, reliability and safety of the
gas and electricity systems and to meet customer growth. All costs
considered to be maintenance and repairs are expensed as incurred.
Costs related to replacements, upgrades and betterments of capital
assets are capitalized as incurred.
A breakdown of the $794 million in gross capital expenditures by
segment year-to-date 2012 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date September 30, 2012
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regula- Total Regula-
ted Regula ted
Elec- - Elec- Non-
Fortis tric ted tric Regula-
BC Fortis New- Utili- Utili- Utili- ted -
Energy Fortis BC found- ties - ties - ties - Utili- Fortis
Compa- Alberta Elec- land Cana- Cana- Carib- ty Proper-
nies (2) tric Power dian dian bean (3) ties Total
----------------------------------------------------------------------------
144 304 52 58 35 593 33 144 24 794
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(1) Relates to cash payments to acquire or construct utility capital
assets, income producing properties and intangible assets, as
reflected in the consolidated statement of cash flows. Includes non-
ARO removal expenditures, net of salvage proceeds, for those utilities
where such expenditures are permissible in rate base in 2012. Excludes
capitalized depreciation and amortization and non-cash equity
component of AFUDC.
(2) Includes payments made to AESO for investment in transmission-related
capital projects
(3) Includes non-regulated generation capital expenditures, mainly related
to the Waneta Expansion
Planned capital expenditures are based on detailed forecasts of
energy demand, weather, cost of labour and materials, as well as
other factors, including economic conditions, which could change
and cause actual expenditures to differ from forecasts.
There have been no material changes in the overall expected
level, nature and timing of the Corporation's significant capital
projects from those that were disclosed in the 2011 Annual
MD&A. Gross consolidated capital expenditures for 2012 are
forecasted at approximately $1.3 billion.
FEI's Customer Care Enhancement Project, at an estimated total
project cost of $110 million, came into service at the beginning of
January 2012.
Construction progress on the $900 million Waneta Expansion is
going well and the project is currently on schedule and on budget.
Major construction activities on-site include the completion of the
excavation of the intake, powerhouse and power tunnels.
Approximately $380 million in total has been spent on the Waneta
Expansion since construction began late in 2010.
Over the five-year period 2012 through 2016, consolidated gross
capital expenditures are expected to be approximately $5.5 billion,
consistent with that disclosed in the 2011 Annual MD&A. The
addition of CH Energy Group is expected to add approximately $0.5
billion to the Corporation's consolidated capital expenditure
program from 2013 through 2016. Approximately 64% of the $5.5
billion capital program is expected to be incurred at the regulated
electric utilities, driven by FortisAlberta and FortisBC Electric.
Approximately 23% and 13% of the capital program is expected to be
incurred at the regulated gas utilities and non-regulated
operations, respectively. Capital expenditures at the regulated
utilities are subject to regulatory approval. Over the five-year
period, excluding CH Energy Group, on average annually, 39% of
utility capital spending is expected to be incurred to meet
customer growth; 38% is expected to be incurred to ensure continued
and enhanced performance, reliability and safety of generation and
T&D assets (i.e., sustaining capital expenditures); and 23% is
expected to be incurred for facilities, equipment, vehicles,
information technology and other assets.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses
and interest costs will generally be paid out of subsidiary
operating cash flows, with varying levels of residual cash flow
available for subsidiary capital expenditures and/or dividend
payments to Fortis. Borrowings under credit facilities may be
required from time to time to support seasonal working capital
requirements. Cash required to complete subsidiary capital
expenditure programs is also expected to be financed from a
combination of borrowings under credit facilities, equity
injections from Fortis and long-term debt offerings.
The Corporation's ability to service its debt obligations and
pay dividends on its common shares and preference shares is
dependent on the financial results of the operating subsidiaries
and the related cash payments from these subsidiaries. Certain
regulated subsidiaries may be subject to restrictions that may
limit their ability to distribute cash to Fortis.
Cash required of Fortis to support subsidiary capital
expenditure programs and finance acquisitions is expected to be
derived from a combination of borrowings under the Corporation's
committed credit facility and proceeds from the issuance of common
shares, preference shares and long-term debt. Depending on the
timing of cash payments from the subsidiaries, borrowings under the
Corporation's committed credit facility may be required from time
to time to support the servicing of debt and payment of
dividends.
As at September 30, 2012, management expects consolidated
long-term debt maturities and repayments to average approximately
$295 million annually over the next five years. The combination of
available credit facilities and relatively low annual debt
maturities and repayments provide the Corporation and its
subsidiaries with flexibility in the timing of access to capital
markets.
In May 2012 Fortis filed a base shelf prospectus under which
Fortis may, from time to time during the 25-month period from May
10, 2012, offer, by way of a prospectus supplement, common shares,
preference shares, subscription receipts and/or unsecured
debentures in the aggregate amount of up to $1.3 billion (or the
equivalent in US dollars or other currencies). The base shelf
prospectus provides the Corporation with flexibility to access
securities markets in a timely manner. The nature, size and timing
of any offering of securities under the Corporation's base shelf
prospectus will be consistent with the past capital raising
practices of the Corporation and continue to be dependant upon the
Corporation's assessment of its requirements for funding and
general market conditions.
To finance a portion of the Corporation's pending acquisition of
CH Energy Group, Fortis offered and sold, by way of a prospectus
supplement, approximately $601 million in Subscription Receipts
under a bought-deal offering with a syndicate of underwriters. For
further information refer to the "Significant Items" and "Business
Risk Management" sections of this MD&A.
As the hydroelectric assets and water rights of the Exploits
River Hydro Partnership ("Exploits Partnership") had been provided
as security for the Exploits Partnership term loan, the
expropriation of such assets and rights by the Government of
Newfoundland and Labrador constituted an event of default under the
loan. The term loan is without recourse to Fortis and was
approximately $55 million as at September 30, 2012 (December 31,
2011 - $56 million). The lenders of the term loan have not demanded
accelerated repayment. The scheduled repayments under the term loan
are being made by Nalcor Energy, a Crown corporation, acting as
agent for the Government of Newfoundland and Labrador with respect
to expropriation matters. For further information refer to Note 19
to the Corporation's interim unaudited consolidated financial
statements for the three and nine months ended September 30,
2012.
Except for the debt at the Exploits Partnership, as discussed
above, Fortis and its subsidiaries were in compliance with debt
covenants as at September 30, 2012 and are expected to remain
compliant throughout the remainder of 2012.
CREDIT FACILITIES
As at September 30, 2012, the Corporation and its subsidiaries
had consolidated credit facilities of approximately $2.5 billion,
of which $2.0 billion was unused, including $764 million unused
under the Corporation's $1 billion committed revolving corporate
credit facility. The credit facilities are syndicated mostly with
the seven largest Canadian banks, with no one bank holding more
than 20% of these facilities. Approximately $2.3 billion of the
total credit facilities are committed facilities with maturities
ranging from 2013 through 2017.
The following summary outlines the credit facilities of the
Corporation and its subsidiaries.
----------------------------------------------------------------------------
Credit Facilities (Unaudited) As at
September December
Regulated Fortis Corporate 30, 31,
($ millions) Utilities Properties and Other 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit facilities 1,401 13 1,045 2,459 2,248
Credit facilities
utilized:
Short-term borrowings (97) - - (97) (159)
Long-term debt
(including current
portion) (63) - (236) (299) (74)
Letters of credit
outstanding (67) - (1) (68) (66)
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Credit facilities
unused 1,174 13 808 1,995 1,949
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As at September 30, 2012 and December 31, 2011, certain
borrowings under the Corporation's and subsidiaries' credit
facilities were classified as long-term debt. These borrowings are
under long-term committed credit facilities and management's
intention is to refinance these borrowings with long-term permanent
financing during future periods.
In March 2012 Newfoundland Power renegotiated and amended its
$100 million unsecured committed revolving credit facility,
obtaining an extension to the maturity of the facility from August
2015 to August 2017. The amended credit facility agreement reflects
a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility
agreement.
In April 2012 FortisBC Electric renegotiated and amended its
credit facility agreement resulting in an extension to the maturity
of the Company's $150 million unsecured committed revolving credit
facility with $100 million now maturing in May 2015 and $50 million
now maturing in May 2013.
In May 2012 FHI extended its $30 million operating credit
facility to mature in May 2013 from May 2012. The new agreement
contains substantially similar terms and conditions as the previous
credit facility agreement.
In May 2012 Fortis increased the amount available for borrowing
under its unsecured committed revolving corporate credit facility
from $800 million to $1 billion, as permitted under the credit
facility agreement.
In May 2012 Caribbean Utilities renegotiated and increased the
amount available for borrowing under its unsecured credit
facilities to US$47 million from US$33 million.
In June 2012 FortisOntario entered into a new short-term credit
facility agreement for $30 million, replacing two short-term credit
facilities totaling $20 million. The new credit facility agreement
reflects a decrease in pricing and improved terms and conditions.
In July 2012 the former credit facilities were terminated.
In July 2012 FEI entered into a one-year extension of its $500
million unsecured committed revolving credit facility, extending
the maturity date from August 2013 to August 2014. The amended
credit facility agreement reflects an increase in pricing but,
otherwise, contains substantially similar terms and conditions as
the previous credit facility agreement.
In July 2012 FortisAlberta renegotiated and amended its $250
million unsecured committed revolving credit facility, obtaining an
extension to the maturity of the facility from September 2015 to
August 2016. The amended credit facility agreement reflects a
decrease in pricing but, otherwise, contains substantially similar
terms and conditions as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial
instruments approximate their fair values, reflecting the
short-term maturity, normal trade credit terms and/or nature of
these instruments, except as follows.
----------------------------------------------------------------------------
Financial Instruments
(Unaudited) As at
September 30, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Waneta Partnership
promissory note 46 52 45 49
Long-term debt, including
current portion 5,937 7,476 5,788 7,172
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----------------------------------------------------------------------------
The fair value of long-term debt is calculated using quoted
market prices when available. When quoted market prices are not
available, the fair value is determined by discounting the future
cash flows of the specific debt instrument at an estimated yield to
maturity equivalent to benchmark government bonds or treasury
bills, with similar terms to maturity, plus a credit risk premium
equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt or
promissory note prior to maturity, the fair value estimate does not
represent an actual liability and, therefore, does not include
exchange or settlement costs.
The financial instruments table above excludes the long-term
other asset associated with the Corporation's expropriated
investment in Belize Electricity. The fair value of the
Corporation's expropriated investment in Belize Electricity
determined under the GOB's valuation is significantly lower than
the fair value determined under the Corporation's independent
valuation of the utility. Due to uncertainty in the ultimate amount
and ability of the GOB to pay appropriate fair value compensation
owing to Fortis for the expropriation of Belize Electricity, the
Corporation has recorded the long-term other asset at the carrying
value of the Corporation's previous investment in Belize
Electricity, including foreign exchange impacts, which totalled
approximately $103 million as at September 30, 2012.
Risk Management: The Corporation's earnings from, and net
investments in, foreign subsidiaries are exposed to fluctuations in
the US dollar-to-Canadian dollar exchange rate. The Corporation has
effectively decreased the above-noted exposure through the use of
US dollar borrowings at the corporate level. The foreign exchange
gain or loss on the translation of US dollar-denominated interest
expense partially offsets the foreign exchange loss or gain on the
translation of the Corporation's foreign subsidiaries' earnings,
which are denominated in US dollars. The reporting currency of
Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and
Belize Electric Company Limited ("BECOL") is the US dollar. Belize
Electricity's financial results were denominated in Belizean
dollars, which are pegged to the US dollar.
As at September 30, 2012, the Corporation's corporately issued
US$557 million (December 31, 2011 - US$550 million) long-term debt
had been designated as an effective hedge of the Corporation's
foreign net investments. As at September 30, 2012, the Corporation
had approximately US$19 million (December 31, 2011 - US$6 million)
in foreign net investments remaining to be hedged. Foreign currency
exchange rate fluctuations associated with the translation of the
Corporation's corporately issued US dollar borrowings designated as
effective hedges are recorded in other comprehensive income and
serve to help offset unrealized foreign currency exchange gains and
losses on the net investments in foreign subsidiaries, which gains
and losses are also recorded in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with
its expropriated investment in Belize Electricity does not qualify
for hedge accounting as Belize Electricity is no longer a foreign
subsidiary of Fortis. As a result, during 2011, a portion of
corporately issued debt that previously hedged the former
investment in Belize Electricity was no longer an effective hedge.
Effective from June 20, 2011, foreign exchange gains and losses on
the translation of the long-term other asset associated with Belize
Electricity and the corporately issued US dollar-denominated debt
that previously qualified as a hedge of the investment were
recognized in earnings. The Corporation has recognized in earnings
foreign exchange losses of approximately $3 million and $2.5
million during the three and nine months ended September 30, 2012,
respectively. During the third quarter of 2011, a foreign exchange
gain of $7 million associated with the translation of the
above-noted US dollar-denominated long-term other asset was
partially offset by a $5.5 million ($4.5 million after tax) foreign
exchange loss associated with the translation of previously hedged
US dollar-denominated long-term debt, resulting in a net foreign
exchange gain of approximately $2.5 million after tax.
From time to time, the Corporation and its subsidiaries hedge
exposures to fluctuations in interest rates, foreign exchange rates
and fuel and natural gas prices through the use of derivative
financial instruments. The Corporation and its subsidiaries do not
hold or issue derivative financial instruments for trading
purposes. As at September 30, 2012, the Corporation's derivative
contracts consisted of fuel option contracts, natural gas swap and
option contracts, and gas purchase contract premiums. The fuel
option contracts are held by Caribbean Utilities and the remaining
derivative instruments are held by the FortisBC Energy
companies.
The following table summarizes the Corporation's derivative
financial instruments.
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Derivative Financial Instruments (Unaudited) As at
September December
30, 31,
2012 2011
Carrying Carrying
Value (2) Value (2)
Number of ($ ($
(Liability) Asset Maturity Contracts Volume (1) millions) millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign exchange
forward contract 2012 (3) - - - -
Fuel option
contracts 2013 (4) 4 7 - (1)
Natural gas
derivatives:
Gas swaps and
options 2014 99 36 (60) (135)
Gas purchase
contract
premiums 2014 80 112 1 -
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(1) The volume for fuel option contracts is reported in millions of
imperial gallons and for natural gas derivatives is reported in PJ.
(2) Carrying value is estimated fair value. The (liability) asset
represents the gross derivatives balance.
(3) The foreign exchange forward contract held by FEI expired in April
2012. The carrying value of the contract was less than $1 million as at
December 31, 2011.
(4) The carrying value of the fuel option contracts was less than $1
million as at September 30, 2012.
The fuel option contracts are used by Caribbean Utilities to
reduce the impact of volatility in fuel prices on customer rates,
as approved by the regulator under the Company's Fuel Price
Volatility Management Program. In October 2012 Caribbean Utilities
executed additional fuel option contracts covering the period from
November 1, 2012 to October 31, 2013. With the execution of these
new contracts, approximately 70% of the Company's annual diesel
fuel requirements are under fuel hedging arrangements.
The natural gas derivatives held by the FortisBC Energy
companies are used to fix the effective purchase price of natural
gas, as the majority of the natural gas supply contracts at the
FortisBC Energy companies have floating, rather than fixed, prices.
The price risk management strategy of the FortisBC Energy companies
aims to improve the likelihood that natural gas prices remain
competitive, to mitigate gas price volatility on customer rates and
to reduce the risk of regional price discrepancies. As directed by
the BCUC, FEI and FEVI suspended their commodity hedging activities
in 2011, which has continued into 2012, with the exception of
certain limited swaps as permitted by the BCUC. The existing
hedging contracts will continue in effect through to their maturity
and the FortisBC Energy companies' ability to fully recover the
commodity cost of gas in customer rates remains unchanged.
The changes in the fair values of the fuel option contracts and
natural gas derivatives are deferred as a regulatory asset or
liability for recovery from, or refund to, customers in future
rates, as permitted by the regulators. The fair values of the
derivative financial instruments were recorded in accounts payable
and other current liabilities as at September 30, 2012 and as at
December 31, 2011.
The fair value of the fuel option contracts reflects only the
value of the heating oil derivative and not the offsetting change
in the value of the underlying future purchases of heating oil and
is calculated using published market prices for heating oil. The
fair value of the natural gas derivatives is calculated using the
present value of cash flows based on market prices and forward
curves for the commodity cost of natural gas. The fair values of
the fuel option contracts and natural gas derivatives were
estimates of the amounts that the utilities would have to receive
or pay to terminate the outstanding contracts as at the balance
sheet dates.
The fair values of the Corporation's financial instruments,
including derivatives, reflect point-in-time estimates based on
current and relevant market information about the instruments as at
the balance sheet dates. The estimates cannot be determined with
precision as they involve uncertainties and matters of judgment
and, therefore, may not be relevant in predicting the Corporation's
future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $68
million, as at September 30, 2012, the Corporation had no
off-balance sheet arrangements, such as transactions, agreements or
contractual arrangements with unconsolidated entities, structured
finance entities, special purpose entities or variable interest
entities, that are reasonably likely to materially affect liquidity
or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
There were no changes in the Corporation's significant business
risks year-to-date 2012 from those disclosed in the 2011 Annual
MD&A, except for those described below.
Regulatory Risk: In April 2012 regulatory decisions were
received for 2012-2013 revenue requirements at the FortisBC Energy
companies and for 2012 distribution revenue requirements at
FortisAlberta. Similarly, a decision was received in August 2012
for 2012-2013 revenue requirements at FortisBC Electric. The
receipt of two-year revenue requirements decisions at the FortisBC
utilities helps to provide a level of operating stability for 2012
and 2013.
The recent decision by the AUC to transition distribution
utilities in Alberta to PBR for a five-year period commencing in
2013 is a fundamental change in how these utilities are regulated;
however, the change provides an opportunity for reduced regulatory
burden and the incentive to achieve greater efficiencies and cost
savings, which can lead to improved earnings. Under PBR, there is
greater risk that FortisAlberta's earnings will be negatively
impacted given the length of the PBR term and the uncertainty of
resulting rate adjustments. It is possible that the approved PBR
formula could have an unfavourable impact on FortisAlberta if the
utility's actual costs, including costs associated with certain of
its required capital projects, exceed the costs permitted by the
PBR formula. In the absence of clarification by the AUC, which
would broaden the scope of the recovery of these costs, the PBR
formula conflicts with FortisAlberta's legal right to recover
prudent costs of providing distribution services and to earn a
reasonable ROE. FortisAlberta will be seeking further clarification
regarding the application of the PBR formula in proceedings before
the AUC and has sought leave to appeal the PBR Decision with the
Alberta Court of Appeal.
The regulatory calendar, particularly at the FortisBC utilities,
will be busy to the end of 2012 and into 2013 with various filings,
interrogatories, inquiries and/or hearings occurring, including
that related to the GCOC Proceeding and an expected request for
approval of FortisBC Electric's proposed acquisition of the City of
Kelowna's electrical utility assets. Determinations of cost of
capital and final allowed ROEs for 2013 for FortisAlberta and
Newfoundland Power also remain outstanding. The results of cost of
capital proceedings could materially impact the earnings of the
Corporation's largest utilities.
For further information, refer to the "Material Regulatory
Decisions and Applications" section of this MD&A.
Completion of the Acquisition of CH Energy Group: The
acquisition of CH Energy Group remains subject to NYSPSC approval.
A delay in receiving the approval, and/or conditions imposed, if
any, under such approval, may result in the failure to materialize
some, or all, of the expected benefits of the acquisition of CH
Energy Group or such benefits may not occur within the time periods
anticipated by the Corporation. The realization of such benefits
may also be impacted by other factors beyond the control of
Fortis.
The agreement and plan of merger may be terminated by the
Corporation or CH Energy Group at any time prior to closing in
certain circumstances, including if the acquisition has not closed
by February 20, 2013 provided, however, that if the only
unsatisfied conditions to closing are the obtaining of the
regulatory approvals as defined in the agreement and plan of
merger, then such date shall be extended to August 20, 2013.
A portion of the acquisition purchase price is expected to be
funded by $601 million of escrowed proceeds from the Corporation's
June 2012 Subscription Receipts offering. If conditions precedent
to the closing of the transaction are not fulfilled or waived,
including receipt of NYSPSC approval, by June 30, 2013, or if the
agreement and plan of merger related to the acquisition is
terminated prior to such time, the proceeds from the Subscription
Receipts offering, plus pro rata interest earned, are required to
be returned to the holders of such receipts. As a result, closing
of the transaction subsequent to June 30, 2013 could result in the
Corporation having to raise alternative capital to finance the
acquisition.
For further information refer to the "Significant Items" section
of this MD&A.
Expropriation of Shares in Belize Electricity: In 2008 the newly
elected GOB changed the electricity rate-setting methodology in
Belize to one that did not allow Belize Electricity to recover its
reasonable COS and make a reasonable rate of return on its
investment as required by law and, thereby, it is the Corporation's
position that the GOB has breached covenants that the GOB made when
it sold its shares in Belize Electricity to Fortis in 1999. Relying
on the new rate-setting methodology, the Belize Public Utilities
Commission denied Belize Electricity a customer rate increase in
its June 2008 Final Decision and subsequently amended that decision
to decrease customer rates by 15%, notwithstanding the fact that a
rate increase was required to adequately finance the utility's
operations. The GOB further compounded Belize Electricity's
financial problems when it increased the utility's business tax
from 1.75% to 6.5%, effective in 2010. Due to an increase in the
cost of purchased power, higher business taxes and the above-noted
denial of compensatory customer rates, Belize Electricity required
short-term financial assistance from the GOB in spring 2011. The
GOB chose to prepay some of its electricity bills, as the preferred
alternative of financial assistance from the options proposed by
Belize Electricity, which allowed the utility to meet its power
purchase obligations with the Mexican state-owned Comision Federal
de Electricidad ("CFE") to the end of June 2011, after which time
Belize Electricity would have been able to source most of its
energy power requirements from lower-cost local hydroelectric
generating facilities, rather than from the CFE, coinciding with
the commencement of the rainy season in Belize.
On June 20, 2011, the GOB enacted in one day the Electricity
(Amendment) Act 2011 ("Acquisition Act") and the Electricity
(Assumption of Control over Belize Electricity Limited) Order 2011
("Acquisition Order"), to expropriate the Corporation's majority
ownership investment in Belize Electricity but did not expropriate
any of the minority ownership investments, which continue to be
held by the Social Security Board of Belize and Belizean residents.
The purported public purpose stated in the Acquisition Order, as
the basis of the decision to expropriate Belize Electricity, was
"to maintain an uninterrupted and reliable supply of electricity to
the public". The Corporation's evidence is that there was no risk
of interruption or unreliable electricity supply at the time of
expropriation and, while Belize Electricity had financial
difficulties in 2011, such difficulties were caused by the GOB and,
therefore, the GOB cannot rely on a situation it created to justify
expropriating Belize Electricity.
Four days after expropriation of the Corporation's investment in
Belize Electricity, the Belize Court of Appeal delivered its
judgment that a similar expropriation of control of Belize
Telemedia Limited ("Belize Telemedia"), a public telecommunications
provider in Belize, in 2009 was unconstitutional, null and void.
Rather than accept and appeal the judgment, the GOB enacted revised
expropriation legislation to retain control of Belize Telemedia and
contemporaneously proposed a constitutional amendment, the
purported effect of which was to: (i) declare the GOB ownership of
three specifically identified public utility providers, including
Belize Electricity and Belize Telemedia; (ii) deem the
expropriation of Belize Electricity and re-expropriation of Belize
Telemedia to have been done for a public purpose; and (iii) oust
the jurisdiction of the Belize Courts to review the GOB
expropriation actions.
On October 21, 2011, Fortis filed a claim ("Claim No. 673 of
2011") in the Belize Supreme Court challenging the GOB's
expropriation of the Corporation's investment in Belize Electricity
pursuant to the Acquisition Act and Acquisition Order. On October
25, 2011, the Belize Constitution (Eighth Amendment) Act 2011
("Eighth Amendment") was enacted to validate and immunize the GOB's
expropriation of Belize Electricity and Belize Telemedia. As a
consequence of the above, Fortis subsequently amended its Claim No.
673 of 2011 to additionally challenge the constitutionality of the
Eighth Amendment.
On June 11, 2012, the trial division of the Belize Supreme Court
delivered its judgment in the claims of British Caribbean Bank
Limited v Attorney General et al ("Claim No. 597 of 2011") and Dean
Boyce v Attorney General et al ("Claim No. 646 of 2011")
(collectively the "Telemedia Judgment") regarding the purported
re-expropriation of Belize Telemedia. The court determined that the
re-expropriation of the Claimants' properties by the GOB in those
claims was unconstitutional, null and void. The judge determined
most of the Eighth Amendment to be invalid, but found that he could
sever those portions of sections 143 and 144 which declare GOB
ownership of the named utilities, and that the severance thereby
prevented the judge from ordering divestiture of the GOB's control
of Belize Telemedia and hence the judge found himself precluded by
the Belize Constitution from granting the Claimants the
consequential relief sought.
Hearing of the Corporation's Claim No. 673 of 2011 occurred on
July 2, 2012 before the same judge who delivered the Telemedia
Judgment. The judge believed he was bound by his reasons in the
Telemedia Judgment and dismissed the Corporation's Claim No. 673 of
2011 on the grounds that the severed portions of the Eighth
Amendment precluded divestiture of the GOB ownership and control of
Belize Electricity, notwithstanding the Acquisition Act and
Acquisition Order, which are virtually identical to the provisions
of the 2009 expropriation of Belize Telemedia, and were found to be
invalid by the Belize Court of Appeal. The judge, therefore, denied
the relief sought by Fortis.
On July 5, 2012, Fortis filed its appeal of the above-noted July
2, 2012 trial judgment to the Belize Court of Appeal. The Belize
Court of Appeal allowed an application for consolidation of the
Corporation's appeal with the appeal and cross-appeal of the
Telemedia Judgment, and directed that the appeals be heard on an
expedited basis commencing October 8, 2012.
In its appeal, Fortis has submitted that the Acquisition Act
violates the Belize Constitution and should be struck down as: (i)
the Acquisition Act does not prescribe the principles and manner in
which reasonable compensation is to be determined in a reasonable
time; (ii) the Acquisition Act does not prescribe the principles
and manner in which reasonable compensation is to be given in a
reasonable time; (iii) the Acquisition Act does not provide a right
of access to the Belize Court for the purpose of enforcing a right
to compensation; and (iv) certain sections of the Acquisition Act
violate certain sections of the Belize Constitution. Fortis also
submitted that the Acquisition Order violates the Corporation's
constitutional rights and should be struck down as: (i) it is not
proportionate; (ii) the expropriation of Belize Electricity by the
GOB was arbitrary as the GOB did not acquire the minority
shareholdings of the Social Security Board or Belizean nationals in
Belize Electricity and is, therefore, in violation of the Belize
Constitution; and (iii) Fortis was not afforded a right to be heard
by the Belize Minister of Public Utilities before its property was
compulsorily acquired by the GOB. Fortis also contends that the
application of saved portions of sections 143 and 144 of the Eighth
Amendment are also invalid and should not have precluded the
ordering of consequential relief to Fortis for several reasons,
including that fact that such provisions are void as they: (i)
deprive the Belize Court of jurisdiction to conduct the
constitutionally mandated inquiry to determine a person's interest
or right in property compulsorily acquired, whether such
acquisition was for a public purpose, the amount of compensation to
which a person is entitled and for enforcement of a person's right
to any such compensation; (ii) are in breach of the principle of
equality before the law and the rule of law; and (iii) on their own
do not fulfill the intention of the legislature of the Belize
Government and are inextricably bound up with the legislation ruled
to be unconstitutional in the Telemedia Judgment.
The consolidated appeal hearing occurred from October 8 to
October 10, 2012. However, since one of the judges on the panel is
the subject of a complaint to the Belize Judicial Council by
parties to the Telemedia Judgment, an application for
disqualification of that judge was made and subsequently denied by
a majority of the appeal panel. Reasons for denial of leave to
appeal of the disqualification application was delivered and
judgment on the consolidated appeal hearing has been suspended,
pending the outcome of the appeal in the Caribbean Court of Justice
("CCJ") relating to the disqualification application. Counsel for
the GOB admitted during the consolidated appeal hearing that the
Acquisition Act and Acquisition Order were contrary to the laws of
Belize as it now stands, on the basis of the Belize Court of Appeal
decision regarding the 2009 expropriation of Belize Telemedia, but
that the severed provisions of the Eighth Amendment preclude return
of majority control over Belize Electricity back to Fortis. A
possible outcome of the consolidated appeal could be the return to
Fortis of the majority ownership interest in Belize Electricity.
Alternatively, in the event that the Belize Court of Appeal
decision confirms the trial judgment, Fortis could pursue an appeal
of the case to the CCJ, the highest court of appeal available for
judicial matters in Belize.
Consequent to the deprivation of control over the operations of
Belize Electricity, the Corporation discontinued the consolidation
method of accounting for the utility, effective June 20, 2011. The
Corporation has classified the book value of the expropriated
investment in Belize Electricity as a long-term other asset on the
consolidated balance sheet. As at September 30, 2012, the long-term
other asset, including foreign exchange impacts, totalled $103
million (December 31, 2011 - $106 million; September 30, 2011 -
$103 million). Fortis commissioned an independent valuation of its
expropriated investment in Belize Electricity and submitted its
claim for compensation to the GOB in November 2011. The book value
of the long-term other asset is below fair value as at the date of
expropriation as determined under the Corporation's valuation. The
GOB also commissioned a valuation of Belize Electricity and
communicated the results of such valuation in its response to the
Corporation's claim for compensation. The fair value of Belize
Electricity determined under the GOB's valuation is significantly
lower than both the fair value determined under the Corporation's
valuation and the book value of the long-term other asset. While
Fortis and representatives and third-party consultants of the GOB
have held discussions in 2012 on differences in assumptions used in
the valuations, there have been no discussions on any compensation
settlement amount.
Fortis believes it has a strong, well-positioned case before the
Belize Courts and will continue to vigorously litigate the legality
of the expropriation. There exists, however, a reasonable
possibility that the outcome of the above-noted litigation may be
unfavourable to the Corporation and the amount of compensation to
be paid to Fortis could be lower than the book value of its
expropriated investment in Belize Electricity. Based on presently
available information, the outcome of the above is not determinable
at this time. As such, the long-term other asset is not deemed
impaired. Fortis will continue to assess for impairment each
reporting period based on the outcomes of court proceedings and/or
compensation settlement negotiations, if any. As well as continuing
its legal actions, Fortis is also pursuing alternative options for
obtaining fair compensation.
Fortis continues to control and consolidate the financial
statements of BECOL, the Corporation's indirect wholly owned
non-regulated hydroelectric generating subsidiary in Belize. As at
October 31, 2012, Belize Electricity owed BECOL US$10 million for
overdue energy purchases representing over 40% of BECOL's annual
sales to Belize Electricity. In accordance with long-standing
agreements, the GOB guarantees the payment of Belize Electricity's
obligations to BECOL.
Capital Resources and Liquidity Risk - Credit Ratings: In May
2012 and July 2012, S&P and DBRS, respectively, affirmed the
Corporation's debt credit ratings. Due to the Corporation's
financing plans for the pending acquisition of CH Energy Group and
the expected completion of the Waneta Expansion on time and on
budget, S&P and DBRS also removed the ratings from credit watch
with negative implications and under review with developing
implications, respectively, where the ratings had been placed in
February 2012. Similarly, FortisAlberta's existing debt credit
rating by S&P was confirmed in May 2012 and removed from credit
watch with negative implications. There were no other changes in
the credit ratings of the Corporation's utilities year-to-date
2012.
Power Supply and Capacity Purchase Contracts: In November 2011
FortisBC Electric executed an agreement to purchase capacity from
the Waneta Expansion and submitted the agreement to the BCUC. The
agreement allows FortisBC Electric to purchase capacity over 40
years upon completion of the Waneta Expansion, which is expected to
be in spring 2015. The form of the agreement was originally
accepted for filing by the BCUC in September 2010. In May 2012 the
BCUC determined that the executed agreement is in the public
interest and a hearing is not required. The agreement has been
accepted for filing as an energy supply contract and FortisBC
Electric has been directed by the BCUC to develop a rate-smoothing
proposal as part of a separate submission or as part of FortisBC
Electric's next RRA.
Defined Benefit Pension Plan Assets: As at September 30, 2012,
the fair value of the Corporation's consolidated defined benefit
pension plan assets was $850 million, up $65 million or 8.3%, from
$785 million as at December 31, 2011.
Labour Relations: The collective agreement between FortisBC
Electric and the Canadian Office and Professional Employees Union
("COPE"), Local 378, expired on January 31, 2011. A new collective
agreement expiring in March 2014 was reached with regard to certain
customer service employees who were previously covered under the
expired contract. A tentative agreement has been reached with
regard to the remaining support and technical employees. The
tentative agreement expires on December 31, 2013 and is subject to
ratification by the affected employees.
The collective agreements between the FortisBC Energy companies
and the International Brotherhood of Electrical Workers ("IBEW"),
Local 213, expired on March 31, 2011. IBEW, Local 213, represents
employees in specified occupations in the areas of T&D. A new
four-year collective agreement, expiring in March 2015, was reached
in June 2012.
The collective agreements between the FortisBC Energy companies
and COPE, Local 378, expired on March 31, 2012. COPE, Local 378,
represents employees in specified occupations in the areas of
administration and operations support. The parties are negotiating
the terms of a renewed collective agreement.
The two collective agreements between Newfoundland Power and
IBEW, Local 1620, expired on September 30, 2011. One of the two
newly negotiated collective agreements was ratified during the
first quarter of 2012; the other was ratified in May 2012. The
agreements are for three-year terms expiring in September 2014.
NEW ACCOUNTING STANDARDS AND POLICIES
Transition to US GAAP: In June 2011 the Ontario Securities
Commission issued a decision allowing Fortis and its reporting
issuer subsidiaries to prepare their financial statements,
effective January 1, 2012 through to December 31, 2014, in
accordance with US GAAP without qualifying as U.S. Securities and
Exchange Commission ("SEC") Issuers. The Corporation and its
reporting issuer subsidiaries, therefore, adopted US GAAP as
opposed to International Financial Reporting Standards ("IFRS") on
January 1, 2012 with the restatement of comparative reporting
periods. Earnings recognized under US GAAP are more closely aligned
with earnings recognized under Canadian GAAP, mainly due to the
continued recognition of regulatory assets and liabilities under US
GAAP. A transition to IFRS would likely have resulted in the
derecognition of some, or perhaps all, of the Corporation's
regulatory assets and liabilities and caused significant volatility
in the Corporation's consolidated earnings. On March 16, 2012,
Fortis voluntarily prepared and filed audited consolidated US GAAP
financial statements for the year ended December 31, 2011 with 2010
comparatives on SEDAR. Also included in the voluntary filing were:
(i) a detailed reconciliation between the Corporation's audited
consolidated Canadian GAAP and audited consolidated US GAAP
financial statements for fiscal 2011, including 2010 comparatives;
and (ii) a detailed reconciliation between the Corporation's 2011
interim unaudited consolidated Canadian GAAP and 2011 interim
unaudited consolidated US GAAP financial statements.
New Accounting Policies: Effective January 1, 2012, the FortisBC
Energy companies prospectively adopted the policy of accruing for
non-ARO removal costs in depreciation expense, as requested in
their 2012-2013 RRA and subsequently approved by the regulator in
its April 2012 decision. The accrual of estimated non-ARO removal
costs is included in depreciation expense and the provision balance
is recognized as a long-term regulatory liability. Actual non-ARO
removal costs, net of salvage proceeds, are recorded against the
regulatory liability when incurred. Non-ARO removal costs are
direct costs incurred by the FortisBC Energy companies in taking
assets out of service, whether through actual removal of the assets
or through disconnection of the assets from the transmission or
distribution system. Prior to 2012 estimated non-ARO removal costs,
net of salvage proceeds, were recognized in operating expenses with
variances between actual non-ARO removal costs and those forecasted
for rate-setting purposes recorded in a regulatory deferral account
for future recovery from, or refund to, customers in rates
commencing in 2012. For the three and nine months ended September
30, 2012, non-ARO removal costs of $5 million and $15 million,
respectively, were accrued as a part of depreciation expense. For
the three and nine months ended September 30, 2011, non-ARO removal
costs of approximately $4 million and $12 million, respectively,
were recognized in operating expenses.
Prior to 2012 variances from forecast, adjusted for certain
revenue and cost variances which flowed through to customers, for
rate-setting purposes were shared equally between customers and
FortisBC Electric. As applied for in FortisBC Electric's 2012-2013
RRA and approved by the BCUC, prospectively from January 1, 2012
the above-noted sharing of positive or negative variances is no
longer in effect. Beginning in 2012, variances between actual
electricity revenue and purchased power costs and those forecasted
in determining customer electricity rates are subject to full
deferral account treatment, to be recovered from, or refunded to,
customers in future rates and, therefore, do not impact net
earnings in 2012. Effective January 1, 2012, however, the flow
through treatment for finance charges, as was applied for in
FortisBC Electric's 2012-2013 RRA, was denied by the regulator
pursuant to its revenue requirements decision. As a result, a
retroactive adjustment was recorded in the third quarter of 2012 to
eliminate the flow through treatment. Variances between actual
finance charges from those forecasted in determining customer
electricity rates, therefore, have an impact on net earnings in
2012.
Effective January 1, 2012, as approved by the regulator, the
FortisBC Energy companies are deferring variances between actual
depreciation expense and that forecasted in determining customer
gas rates.
Effective January 1, 2012, as approved by the regulator,
FortisAlberta is no longer permitted to defer transmission volume
variances associated with its AESO charges deferral account. For
the three and nine months ended September 30, 2012, FortisAlberta
recognized approximately $3.5 million and $6.5 million,
respectively, of net transmission revenue as a result of this
change.
New US GAAP Accounting Pronouncements: The new US GAAP
accounting pronouncements that are applicable to, and were adopted
by, Fortis effective January 1, 2012 are described as follows:
Presentation of Comprehensive Income
The Corporation adopted the amendments to Accounting Standards
Codification ("ASC") Topic 220, Comprehensive Income. The amended
standard requires entities to report components of comprehensive
income in either a continuous statement of comprehensive income or
two separate but consecutive statements. Fortis continues to report
the components of comprehensive income in a separate but
consecutive statement.
Testing Goodwill for Impairment
The Corporation adopted the amendments to ASC Topic 350,
Goodwill. The amended standard allows entities testing goodwill for
impairment to have the option of performing a qualitative
assessment before calculating the fair value of the reporting unit.
If the qualitative factors indicate that the fair value of the
reporting unit is more likely than not (i.e., greater than a 50%
chance) to be greater than the carrying value, then the two-step
impairment test, including the quantification of the fair value of
the reporting unit, would not be required. In adopting the
amendments, Fortis will perform a qualitative assessment before
calculating the fair value of its reporting units when it performs
its annual impairment test as of October 1.
Fair Value Measurement
The Corporation adopted the amendments to ASC Topic 820, Fair
Value Measurements and Disclosures. The amended standard improves
comparability of fair value measurements presented and disclosed in
financial statements prepared in accordance with US GAAP. The
amendment does not change what items are measured at fair value but
instead makes various changes to the guidance pertaining to how
fair value is measured. The above-noted changes did not materially
impact the Corporation's interim unaudited consolidated financial
statements for the three and nine months ended September 30,
2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited
consolidated financial statements in accordance with US GAAP
requires management to make estimates and judgments that affect the
reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are
based on historical experience, current conditions and various
other assumptions believed to be reasonable under the
circumstances. Additionally, certain estimates and judgments are
necessary since the regulatory environments in which the
Corporation's utilities operate often require amounts to be
recorded at estimated values until these amounts are finalized
pursuant to regulatory decisions or other regulatory proceedings.
During the second quarter of 2012, the FortisBC Energy companies
and FortisAlberta received revenue requirements decisions,
effective January 1, 2012, the cumulative impacts of which, where
such impacts were different from those estimated, were recorded in
the second quarter of 2012. Similarly, FortisBC Electric recorded
the cumulative impacts of its revenue requirements decision,
effective January 1, 2012, in the third quarter of 2012 when the
decision was received. Due to changes in facts and circumstances
and the inherent uncertainty involved in making estimates, actual
results may differ significantly from current estimates. Estimates
and judgments are reviewed periodically and, as adjustments become
necessary, are reported in earnings in the period they become
known.
Interim financial statements may also employ a greater use of
estimates than the annual financial statements. There were no
material changes in the nature of the Corporation's critical
accounting estimates year-to-date 2012 from those disclosed in the
2011 Annual MD&A except for that related to capital asset
depreciation. Changes in regulator-approved depreciation rates at
FortisAlberta and FortisBC Electric, in conjunction with approved
depreciation studies and revenue requirements decisions received in
2012, have impacted consolidated depreciation expense. The
composite depreciation rate for utility capital assets at
FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011.
FortisBC Electric's composite depreciation rate for utility capital
assets decreased to 3.1% for 2012 from 3.2% for 2011. As required
by the BCUC, effective January 1, 2012, depreciation rates at the
FortisBC Energy companies now include an amount allowed for
regulatory purposes to accrue for estimated non-ARO removal costs,
net of salvage proceeds. For further information, refer to the "New
Accounting Standards and Policies" section of this MD&A. The
impact of the above-noted changes in depreciation rates on
depreciation expense has been reflected in the utilities' approved
revenue requirements and resulting customer rates.
Contingencies: The Corporation and its subsidiaries are subject
to various legal proceedings and claims associated with ordinary
course business operations. Management believes that the amount of
liability, if any, from these actions would not have a material
effect on the Corporation's consolidated financial position or
results of operations.
The following describes the nature of the Corporation's
contingent liabilities.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed
settlement agreement with counsel to plaintiff shareholders
pertaining to several complaints, which named Fortis and other
defendants, which were filed in, or transferred to, the Supreme
Court of the State of New York, County of New York, relating to the
proposed acquisition of CH Energy Group by Fortis. The complaints
generally alleged that the directors of CH Energy Group breached
their fiduciary duties in connection with the proposed acquisition
and that CH Energy Group, Fortis, FortisUS Inc. and Cascade
Acquisition Sub Inc. aided and abetted that breach. The settlement
agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received
Notices of Assessment from Canada Revenue Agency for additional
taxes related to the taxation years 1999 through 2003. The exposure
has been fully provided for in the consolidated financial
statements. FHI is appealing these assessments.
In 2009 FHI was named, along with other defendants, in an action
related to damages to property and chattels, including
contamination to sewer lines and costs associated with remediation,
related to the rupture in July 2007 of an oil pipeline owned and
operated by Kinder Morgan, Inc. FHI filed a statement of defence.
During the second quarter of 2010, FHI was added as a third party
in all of the related actions. FHI was advised that all matters
have now been settled and the action has been dismissed by
consent.
FortisBC Electric
The Government of British Columbia has alleged breaches of the
Forest Practices Code and negligence relating to a forest fire near
Vaseux Lake and has filed and served a writ and statement of claim
against FortisBC Electric dated August 2, 2005. The Government of
British Columbia has now disclosed that its claim includes
approximately $13.5 million in damages but that it has not fully
quantified its damages. In addition, private landowners have filed
separate writs and statements of claim dated August 19, 2005 and
August 22, 2005 for undisclosed amounts in relation to the same
matter. FortisBC Electric and its insurers are defending the
claims. A date for mediation of this matter has been set for
December 2012. The outcome cannot be reasonably determined and
estimated at this time and, accordingly, no amount has been accrued
in the consolidated financial statements.
The Government of British Columbia filed a claim in the British
Columbia Supreme Court in June 2012 claiming on its behalf, and on
behalf of approximately 17 homeowners, damages suffered as a result
of a landslide caused by a dam failure in Oliver, British Columbia
in 2010. The Government of British Columbia alleges in its claim
that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government
of British Columbia estimates its damages and the damages of the
homeowners, on whose behalf it is claiming, to be approximately $12
million. FortisBC Electric has not been served, however, has
retained counsel and has contacted its insurers. The outcome cannot
be reasonably determined and estimated at this time and,
accordingly, no amount has been accrued in the consolidated
financial statements.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information
for each of the eight quarters ended December 31, 2010 through
September 30, 2012. The quarterly information has been obtained
from the Corporation's interim unaudited consolidated financial
statements, which have been prepared in accordance with US GAAP.
The timing of the recognition of certain assets, liabilities,
revenue and expenses, as a result of regulation, may differ from
that otherwise expected using US GAAP for non-regulated entities.
The nature of regulation is further disclosed in Notes 2, 3 and 7
to the Corporation's 2011 annual audited consolidated financial
statements prepared in accordance with US GAAP. The quarterly
financial results are not necessarily indicative of results for any
future period and should not be relied upon to predict future
performance.
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Summary of Quarterly Results
(Unaudited)
Net Earnings
Attributable
to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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September 30, 2012 714 45 0.24 0.24
June 30, 2012 792 62 0.33 0.33
March 31, 2012 1,149 121 0.64 0.62
December 31, 2011 1,034 82 0.44 0.43
September 30, 2011 699 56 0.30 0.30
June 30, 2011 846 57 0.32 0.32
March 31, 2011 1,159 116 0.66 0.64
December 31, 2010 1,032 127 0.73 0.71
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A summary of the past eight quarters reflects the Corporation's
continued organic growth, growth from acquisitions, as well as the
seasonality associated with its businesses. Interim results will
fluctuate due to the seasonal nature of gas and electricity demand
and water flows, as well as the timing and recognition of
regulatory decisions. Revenue is also affected by the cost of fuel
and purchased power and the commodity cost of natural gas, which
are flowed through to customers without markup. Given the
diversified nature of the Fortis subsidiaries, seasonality may
vary. Most of the annual earnings of the FortisBC Energy companies
are realized in the first and fourth quarters. Earnings for the
first, second and third quarters of 2012 were reduced by
approximately $4 million, $3 million and $0.5 million,
respectively, associated with costs incurred related to the pending
acquisition of CH Energy Group. During the second quarter of 2012,
the FortisBC Energy companies and FortisAlberta received revenue
requirements decisions, effective from January 1, 2012, the
cumulative impacts of which, where such impacts were different from
those estimated, were recorded in the second quarter of 2012.
Similarly, FortisBC Electric recorded the cumulative impacts of its
rate decision, effective January 1, 2012, in the third quarter of
2012 when the decision was received. Financial results from the
fourth quarter ended December 31, 2011 reflected the acquisition of
the Hilton Suites Hotel in October 2011. Earnings for the third
quarter ended September 30, 2011 included the $11 million after-tax
termination fee paid to Fortis by CVPS. Financial results from June
20, 2011 reflected the discontinuance of the consolidation method
of accounting for Belize Electricity due to the expropriation of
the utility by the GOB. For further information, refer to the
"Significant Items" and "Business Risk Management" sections of this
MD&A.
September 2012/September 2011: Net earnings attributable to
common equity shareholders were $45 million, or $0.24 per common
share, for the third quarter of 2012 compared to earnings of $56
million, or $0.30 per common share, for the third quarter of 2011.
A discussion of the quarter over quarter variance in financial
results is provided in the "Financial Highlights" section of this
MD&A.
June 2012/June 2011: Net earnings attributable to common equity
shareholders were $62 million, or $0.33 per common share, for the
second quarter of 2012 compared to earnings of $57 million, or
$0.32 per common share, for the second quarter of 2011. The
increase in earnings was mainly due to higher contribution from
FortisAlberta, increased non-regulated hydroelectric production in
Belize, associated with higher rainfall, and higher earnings at
Newfoundland Power, partially offset by higher corporate expenses
and decreased earnings at the FortisBC Energy companies. Higher
contribution from FortisAlberta related to rate base growth, and
increased net transmission revenue and reduced depreciation as
approved by the regulator, partially offset by a lower allowed ROE.
Higher earnings at Newfoundland Power were the result of lower
effective income taxes and a higher allowed ROE. The cumulative
impact of the increase in the regulator-approved allowed ROE,
effective January 1, 2012, was recorded in the second quarter of
2012. The increase in corporate expenses was due to approximately
$4 million ($3 million after tax) of costs incurred during the
second quarter of 2012 related to the pending acquisition of CH
Energy Group and a lower income tax recovery, partially offset by a
foreign exchange gain of approximately $2 million recognized in the
second quarter of 2012. Decreased earnings at the FortisBC Energy
companies mainly related to lower-than-expected customer additions
in 2012 and lower capitalized AFUDC, partially offset by higher gas
transportation volumes to industrial customers. A 7% increase in
the weighted average number of common shares outstanding quarter
over quarter, largely associated with the issuance of common equity
mid-2011, had the impact of lowering earnings per common share in
the second quarter of 2012.
March 2012/March 2011: Net earnings attributable to common
equity shareholders were $121 million, or $0.64 per common share,
for the first quarter of 2012 compared to earnings of $116 million,
or $0.66 per common share, for the first quarter of 2011. The
increase in earnings was mainly due to higher contribution from the
FortisBC Energy companies, increased non-regulated hydroelectric
production in Belize, associated with higher rainfall, and higher
earnings at Newfoundland Power and Maritime Electric, mainly the
result of increased electricity sales and lower effective corporate
income taxes. The increase in earnings was partially offset by the
impact of the expiry of the PBR mechanism on December 31, 2011 at
FortisBC Electric and the timing of certain operating expenses at
the utility in 2012, higher corporate expenses and an approximate
$1 million gain on the sale of property at FortisAlberta during the
first quarter of 2011. The increase in earnings at the FortisBC
Energy companies mainly related to the favourable impact of the
difference in the timing of recognition of revenue associated with
seasonal gas consumption and certain increased regulator-approved
expenses in 2012, rate base growth and higher gas transportation
volumes to industrial customers, partially offset by
lower-than-expected customer additions in 2012 and lower
capitalized AFUDC. The increase in corporate expenses was the
result of approximately $4 million ($4 million after tax) of costs
incurred during the first quarter of 2012 related to the pending
acquisition of CH Energy Group and a $1.5 million foreign exchange
loss, partially offset by lower finance charges. An 8% increase in
the weighted average number of common shares outstanding quarter
over quarter, largely associated with the issuance of common equity
mid-2011, had the impact of lowering earnings per common share in
the first quarter of 2012.
December 2011/December 2010: Net earnings attributable to common
equity shareholders were $82 million, or $0.44 per common share,
for the fourth quarter of 2011 compared to earnings of $127
million, or $0.73 per common share, for the fourth quarter of 2010.
Excluding the one-time $46 million favourable impact to
Newfoundland Power's earnings in the fourth quarter of 2010 due to
the rerecognition of a regulatory asset, as required under US GAAP,
to recognize amounts recoverable from customers upon regulatory
approval of the adoption the accrual method of accounting for OPEB
costs, earnings increased $1 million quarter over quarter. The
increase in earnings was led by the FortisBC Energy companies,
driven by rate base growth, lower-than-expected corporate income
taxes and finance charges in 2011, and higher gas transportation
volumes to industrial customers, partially offset by both lower
customer additions and capitalized AFUDC in 2011. The above-noted
increase in earnings was partially offset by a decrease in earnings
at Newfoundland Power, Other Canadian Regulated Electric Utilities,
Fortis Turks and Caicos and Fortis Properties. The decrease in
earnings at Newfoundland Power reflected a lower allowed ROE and
higher operating expenses, partially offset by reduced energy
supply costs in the fourth quarter of 2011. Lower earnings at Other
Canadian Regulated Electric Utilities were due to decreased
electricity sales and higher operating expenses. Lower earnings at
Fortis Turks and Caicos were due to higher depreciation and
operating expenses, partially offset by reduced energy supply costs
in 2011 reflecting the use of new, more fuel-efficient generating
units. Earnings at Fortis Properties during the fourth quarter of
2010 reflected lower corporate income tax rates, which reduced
deferred taxes in that period. An 8% increase in the weighted
average number of common shares outstanding quarter over quarter,
largely associated with the issuance of common equity in mid-2011,
had the impact of lowering earnings per common share in the fourth
quarter of 2011.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
In an effort to optimize customer service operations within the
FortisBC Energy companies, a Customer Care Enhancement Project was
implemented at the beginning of January 2012 with new in-house
customer contact and billing centres replacing the services of an
external third-party service provider. This represents a material
change in the Corporation's internal controls over financial
reporting surrounding the revenue, receivable and receipts cycle.
Throughout the related systems design and implementation,
management had considered the control risks associated with the
systems changes and had performed procedures to obtain reasonable
assurance on the design of all new and significantly modified
internal controls over financial reporting as a result of the
project. It has been concluded that year-to-date 2012, other than
the above-noted change, there were no changes in the Corporation's
internal controls over financial reporting that have materially, or
are reasonably likely to materially affect, the Corporation's
internal controls over financial reporting.
OUTLOOK
The Corporation's significant capital expenditure program, which
is expected to be approximately $5.5 billion over the five-year
period 2012 through 2016, should support continuing growth in
earnings and dividends. CH Energy Group is expected to add
approximately $0.5 billion to the Corporation's consolidated
capital expenditure program from 2013 through 2016.
Fortis is focused on closing the CH Energy Group transaction by
the end of the first quarter of 2013. Approval of the transaction
by the NYSPSC is the one remaining significant regulatory
matter.
Fortis remains disciplined and patient in its pursuit of
additional electric and gas utility acquisitions in the United
States and Canada that will add value for Fortis shareholders.
Fortis will also pursue growth in its non-regulated businesses in
support of its regulated utility growth strategy.
SUBSEQUENT EVENT
In October 2012 FortisAlberta issued 40-year $125 million 3.98%
senior unsecured debentures, the proceeds of which are being used
to repay borrowings under the Company's credit facility, fund
future capital expenditures, and for general corporate
purposes.
OUTSTANDING SHARE DATA
As at October 31, 2012, the Corporation had issued and
outstanding approximately 190.7 million common shares; 5.0 million
First Preference Shares, Series C; 8.0 million First Preference
Shares, Series E; 5.0 million First Preference Shares, Series F;
9.2 million First Preference Shares, Series G; 10.0 million First
Preference Shares, Series H; and 18.5 million Subscription
Receipts. Only the common shares of the Corporation have regular
voting rights. The Corporation's First Preference Shares do not
have voting rights unless and until Fortis fails to pay eight
quarterly dividends, whether or not consecutive and whether or not
such dividends have been declared.
The number of common shares of Fortis that would be issued if
all outstanding stock options, First Preference Shares, Series C
and E, and Subscription Receipts were converted as at October 31,
2012 is as follows.
----------------------------------------------------------------------------
Conversion of Securities into Common Shares (Unaudited)
As at October 31, 2012 Number of
Common Shares
Security (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options 5.1
First Preference Shares, Series C 3.9
First Preference Shares, Series E 6.2
Subscription Receipts 18.5
----------------------------------------------------------------------------
Total 33.7
----------------------------------------------------------------------------
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Additional information, including the Fortis 2011 Annual
Information Form, Management Information Circular and Annual
Report, is available on SEDAR at www.sedar.com and on the
Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and nine months ended September 30, 2012 and 2011
(Unaudited)
Prepared in accordance with accounting principles generally
accepted in the United States
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30, December 31,
2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 22)
ASSETS
Current assets
Cash and cash equivalents $ 147 $ 87
Accounts receivable 410 638
Prepaid expenses 33 19
Inventories 157 134
Regulatory assets (Note 3) 98 219
Deferred income taxes 24 24
--------------------------------
869 1,121
Other assets 209 184
Regulatory assets (Note 3) 1,493 1,400
Deferred income taxes 1 8
Utility capital assets 9,374 8,968
Income producing properties 604 594
Intangible assets 322 325
Goodwill (Note 12) 1,566 1,565
--------------------------------
$ 14,438 $ 14,165
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 17) $ 97 $ 159
Accounts payable and other current
liabilities 855 990
Regulatory liabilities (Note 3) 75 43
Current installments of long-term debt 90 103
Current installments of capital lease and
finance obligations 7 7
Deferred income taxes 2 5
--------------------------------
1,126 1,307
Other liabilities 577 573
Regulatory liabilities (Note 3) 588 555
Deferred income taxes 733 673
Long-term debt 5,847 5,685
Capital lease and finance obligations 434 429
--------------------------------
9,305 9,222
--------------------------------
Shareholders' equity
Common shares (a)(Note 4) 3,092 3,036
Preference shares 912 912
Additional paid-in capital 15 14
Accumulated other comprehensive loss (97) (95)
Retained earnings 923 868
--------------------------------
4,845 4,735
Non-controlling interests (Note 5) 288 208
--------------------------------
5,133 4,943
--------------------------------
$ 14,438 $ 14,165
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) no par value: unlimited authorized shares; 190.7 million and 188.8
million issued and outstanding as at
September 30, 2012 and December 31, 2011, respectively
Commitments and Contingent Liabilities (Notes 18 and 20, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 714 $ 699 $ 2,655 $ 2,704
-----------------------------------------
Expenses
Energy supply costs 235 246 1,092 1,207
Operating 203 200 621 619
Depreciation and amortization 118 104 351 309
-----------------------------------------
556 550 2,064 2,135
-----------------------------------------
Operating income 158 149 591 569
Other income (expenses), net (Note
8) 1 22 (2) 34
Finance charges (Note 9) 93 89 276 274
-----------------------------------------
Earnings before income taxes 66 82 313 329
Income taxes (Note 10) 7 12 44 59
-----------------------------------------
Net earnings $ 59 $ 70 $ 269 $ 270
-----------------------------------------
-----------------------------------------
Net earnings attributable to:
Non-controlling interests $ 3 $ 3 $ 7 $ 7
Preference equity shareholders 11 11 34 34
Common equity shareholders 45 56 228 229
-----------------------------------------
$ 59 $ 70 $ 269 $ 270
-----------------------------------------
-----------------------------------------
Earnings per common share (Note 11)
Basic $ 0.24 $ 0.30 $ 1.20 $ 1.28
Diluted $ 0.24 $ 0.30 $ 1.19 $ 1.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 59 $ 70 $ 269 $ 270
--------------------------------------
--------------------------------------
Other comprehensive (loss) income
Unrealized foreign currency
translation (losses) gains, net of
hedging activities and tax (3) 8 (3) 5
Reclassification of unrealized foreign
currency translation losses, net of
hedging activities and tax, related
to Belize Electricity - - - 17
Reclassification to earnings of net
losses on discontinued cash flow
hedges, net of tax - 1 - 1
Unrealized employee future benefits
gains, net of tax - - 1 -
--------------------------------------
(3) 9 (2) 23
--------------------------------------
Comprehensive income $ 56 $ 79 $ 267 $ 293
--------------------------------------
--------------------------------------
Comprehensive income attributable to:
Non-controlling interests $ 3 $ 3 $ 7 $ 7
Preference equity shareholders 11 11 34 34
Common equity shareholders 42 65 226 252
--------------------------------------
$ 56 $ 79 $ 267 $ 293
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 59 $ 70 $ 269 $ 270
Adjustments to reconcile net
earnings to net cash provided by
operating activities:
Depreciation - utility capital
assets and income producing
properties 105 95 316 284
Amortization - intangible assets 12 9 33 27
Amortization - other 1 - 2 (2)
Deferred income taxes - 4 8 3
Accrued employee future benefits 3 4 (4) 13
Equity component of allowance for
funds used construction (Note 8) (1) (2) (4) (10)
Other 1 - (10) 4
Change in long-term regulatory
assets and liabilities (16) (27) (25) (9)
Change in non-cash operating working
capital (Note 14) 57 (2) 219 104
----------------------------------------
221 151 804 684
----------------------------------------
Investing activities
Change in other assets and other
liabilities (2) 3 2 1
Capital expenditures - utility
capital assets (264) (259) (737) (745)
Capital expenditures - income
producing properties (9) (11) (24) (20)
Capital expenditures - intangible
assets (10) (16) (33) (39)
Contributions in aid of construction 15 18 45 49
Proceeds on sale of utility capital
assets and income producing
properties - - - 6
Business acquisitions, net of cash
acquired (Note 12) (7) - (14) -
----------------------------------------
(277) (265) (761) (748)
----------------------------------------
Financing activities
Change in short-term borrowings 17 86 (61) (114)
Proceeds from long-term debt, net of
issue costs - 9 - 39
Repayments of long-term debt and
capital lease and finance
obligations - (3) (57) (27)
Net (repayments) borrowings under
committed credit facilities (9) (178) 221 (105)
Advances from non-controlling
interests 14 20 83 77
Subscription Receipts issue costs
(Note 4) (1) - (13) -
Issue of common shares, net of costs
and dividends reinvested 6 40 12 341
Dividends
Common shares, net of dividends
reinvested (42) (38) (128) (109)
Preference shares (11) (11) (34) (34)
Subsidiary dividends paid to non-
controlling interests (2) (2) (6) (6)
----------------------------------------
(28) (77) 17 62
----------------------------------------
Effect of exchange rate changes on
cash and cash equivalents - 1 - 1
----------------------------------------
Change in cash and cash equivalents (84) (190) 60 (1)
Cash and cash equivalents, beginning
of period 231 296 87 107
----------------------------------------
Cash and cash equivalents, end of
period $ 147 $ 106 $ 147 $ 106
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note 14)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Accu-
mulated
Addi- Other Non-
Prefe- tional Compre- Control-
Common rence Paid-in hensive Retained ling Total
Shares Shares Capital Loss Earnings Interests Equity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 4)
As at December
31, 2011 $ 3,036$ 912$ 14 $ (95)$ 868 $ 208 $ 4,943
Net earnings - - - - 262 7 269
Other
comprehensive
income - - - (2) - - (2)
Common share
issues 56 - (1) - - - 55
Stock-based
compensation - - 2 - - - 2
Advances from
non-
controlling
interests - - - - - 83 83
Foreign
currency
translation
impacts - - - - - (4) (4)
Subsidiary
dividends
paid to non-
controlling
interests - - - - - (6) (6)
Dividends
declared on
common shares
($0.90 per
share) - - - - (173) - (173)
Dividends
declared on
preference
shares - - - - (34) - (34)
--------------------------------------------------------------
As at
September 30,
2012 $ 3,092$ 912$ 15 $ (97)$ 923 $ 288 $ 5,133
----------------------------------------------------------------------------
As at December
31, 2010 $ 2,575$ 912$ 12 $ (108)$ 774 $ 162 $ 4,327
Net earnings - - - - 263 7 270
Other
comprehensive
income - - - 23 - - 23
Common share
issues 395 - (2) - - - 393
Stock-based
compensation - - 3 - - - 3
Advances from
non-
controlling
interests - - - - - 77 77
Foreign
currency
translation
impacts - - - - - 3 3
Subsidiary
dividends
paid to non-
controlling
interests - - - - - (6) (6)
Expropriation
of Belize
Electricity
(Notes 16, 17
and 19) - - - - - (38) (38)
Dividends
declared on
common shares
($0.87 per
share) - - - - (159) - (159)
Dividends
declared on
preference
shares - - - - (34) - (34)
--------------------------------------------------------------
As at
September 30,
2011 $ 2,970$ 912$ 13 $ (85)$ 844 $ 205 $ 4,859
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2012 and 2011 (unless
otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an
international distribution utility holding company. Fortis segments
its utility operations by franchise area and, depending on
regulatory requirements, by the nature of the assets. Fortis also
holds investments in non-regulated generation assets, and
commercial office and retail space and hotels, which are treated as
two separate segments. The Corporation's reporting segments allow
senior management to evaluate the operational performance and
assess the overall contribution of each segment to the long-term
objectives of Fortis. Each reporting segment operates as an
autonomous unit, assumes profit and loss responsibility and is
accountable for its own resource allocation.
The following outlines each of the Corporation's reportable
segments and is consistent with the basis of segmentation as
disclosed in the Corporation's 2011 annual audited consolidated
financial statements prepared in accordance with accounting
principles generally accepted in the United States ("US GAAP").
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric
utilities in Canada and the Caribbean by utility are as
follows:
a. Regulated Gas Utilities - Canadian: Includes the FortisBC Energy
companies, which is comprised of FortisBC Energy Inc. ("FEI"), FortisBC
Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler)
Inc.
b. Regulated Electric Utilities - Canadian: Includes FortisAlberta;
FortisBC Electric; Newfoundland Power; and Other Canadian Electric
Utilities, which includes Maritime Electric and FortisOntario.
FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall
Street Railway, Light and Power Company, Limited and Algoma Power Inc.
c. Regulated Electric Utilities - Caribbean: Includes Caribbean Utilities,
in which Fortis holds an approximate 60% controlling ownership interest;
three small wholly owned utilities in the Turks and Caicos Islands,
which include Turks and Caicos Utilities Limited ("TCU"), acquired in
August 2012, FortisTCI Limited and Atlantic Equipment & Power (Turks and
Caicos) Ltd. (collectively "Fortis Turks and Caicos"); and the financial
results of the Corporation's approximate 70% controlling interest in
Belize Electricity up to June 20, 2011. Effective June 20, 2011, the
Government of Belize ("GOB") expropriated the Corporation's investment
in Belize Electricity. As a result of no longer controlling the
operations of the utility, Fortis discontinued the consolidation method
of accounting for Belize Electricity, effective June 20, 2011 (Notes 16,
17 and 19).
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of
non-regulated generation assets in Belize, Ontario, central
Newfoundland, British Columbia and Upstate New York. Effective July
1, 2012, the legal ownership of the six small non-regulated
hydroelectric generating facilities in eastern Ontario, with a
combined generating capacity of 8 megawatts ("MW"), was transferred
from Fortis Properties to a limited partnership directly held by
Fortis.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 23 hotels, collectively
representing more than 4,400 rooms, in eight Canadian provinces,
including the acquisition of the StationPark All Suite Hotel in
London, Ontario, which was acquired on October 1, 2012. Fortis
Properties also owns and operates approximately 2.7 million square
feet of commercial office and retail space primarily in Atlantic
Canada.
CORPORATE AND OTHER
The Corporate and Other segment includes Fortis net corporate
expenses and the net expenses of non-regulated FortisBC Holdings
Inc. ("FHI") corporate-related activities. Also included in the
Corporate and Other segment are the financial results of FHI's 30%
ownership interest in CustomerWorks Limited Partnership ("CWLP")
and of FHI's wholly owned subsidiary FortisBC Alternative Energy
Services Inc. ("FAES"). CWLP provides billing and customer care
services to utilities, municipalities and certain energy companies.
The contracts between CWLP and the FortisBC Energy companies ended
on December 31, 2011. FAES provides alternative energy
solutions.
PENDING ACQUISITION
In February 2012 Fortis announced that it had entered into an
agreement to acquire CH Energy Group, Inc. ("CH Energy Group") for
US$65.00 per common share in cash, for an aggregate purchase price
of approximately US$1.5 billion, including the assumption of
approximately US$500 million of debt on closing. CH Energy Group is
an energy delivery company headquartered in Poughkeepsie, New York.
Its main business, Central Hudson Gas & Electric Corporation,
is a regulated transmission and distribution utility serving
approximately 300,000 electric and 75,000 natural gas customers in
eight counties of New York State's Mid-Hudson River Valley. The
transaction received CH Energy Group shareholder approval in June
2012 and regulatory approval from the Federal Energy Regulatory
Commission and the Committee on Foreign Investment in the United
States in July 2012. In addition, the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in
October 2012, satisfying another condition necessary for
consummation of the transaction.
The transaction remains subject to approval by the New York
State Public Service Commission ("NYSPSC") and satisfaction of
customary closing conditions. The application for approval of the
transaction by the NYSPSC was jointly filed by Fortis and CH Energy
Group in April 2012. The acquisition is expected to close by the
end of the first quarter of 2013 and be immediately accretive to
earnings per common share, excluding acquisition-related expenses
(Notes 8 and 18).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been
prepared in accordance with US GAAP for interim financial
statements. As a result, these interim consolidated financial
statements do not include all of the information and disclosures
required in the annual consolidated financial statements and should
be read in conjunction with the Corporation's 2011 annual audited
consolidated financial statements prepared in accordance with US
GAAP and voluntarily filed on the System for Electronic Document
Analysis and Retrieval by Fortis on March 16, 2012 (the
"Corporation's 2011 US GAAP annual audited consolidated financial
statements"). In management's opinion, the interim consolidated
financial statements include all adjustments that are of a
recurring nature and necessary to present fairly the financial
position of the Corporation.
Interim results will fluctuate due to the seasonal nature of gas
and electricity demand and water flows, as well as the timing and
recognition of regulatory decisions. Because of natural gas
consumption patterns, most of the annual earnings of the FortisBC
Energy companies are realized in the first and fourth quarters.
Given the diversified group of companies, seasonality may vary.
The preparation of financial statements in accordance with US
GAAP requires management to make estimates and judgments that
affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are
based on historical experience, current conditions and various
other assumptions believed to be reasonable under the
circumstances. Additionally, certain estimates and judgments are
necessary since the regulatory environments in which the
Corporation's utilities operate often require amounts to be
recorded at estimated values until these amounts are finalized
pursuant to regulatory decisions or other regulatory proceedings.
During the second quarter of 2012, the FortisBC Energy companies
and FortisAlberta received revenue requirements decisions,
effective January 1, 2012, the cumulative impacts of which, where
such impacts were different from those estimated, were recorded in
the second quarter of 2012. Similarly, FortisBC Electric recorded
the cumulative impacts of its revenue requirements decision,
effective January 1, 2012, in the third quarter of 2012 when the
decision was received. Due to changes in facts and circumstances
and the inherent uncertainty involved in making estimates, actual
results may differ significantly from current estimates. Estimates
and judgments are reviewed periodically and, as adjustments become
necessary, are reported in earnings in the period in which they
become known.
Interim financial statements may also employ a greater use of
estimates than the annual financial statements. There were no
material changes in the nature of the Corporation's critical
accounting estimates during the three and nine months ended
September 30, 2012, except as described further with respect to
capital asset depreciation.
An evaluation of subsequent events through to October 31, 2012,
the date these interim consolidated financial statements were
approved by the Audit Committee of the Board of Directors, was
completed to determine whether circumstances warranted recognition
and disclosure of events or transactions in the interim
consolidated financial statements as at September 30, 2012 (Note
21).
All amounts are presented in Canadian dollars unless otherwise
stated.
These interim consolidated financial statements include the
accounts of Fortis and its wholly owned subsidiaries and
controlling ownership interests. All significant intercompany
balances and transactions have been eliminated on
consolidation.
These interim consolidated financial statements have been
prepared following the same accounting policies and methods as
those used in preparing the Corporation's 2011 US GAAP annual
audited consolidated financial statements, except as described
below.
Presentation of Comprehensive Income
Effective January 1, 2012, the Corporation adopted the
amendments to Accounting Standards Codification ("ASC") Topic 220,
Comprehensive Income. The amended standard requires entities to
report components of comprehensive income in either a continuous
statement of comprehensive income or two separate but consecutive
statements. Fortis continues to report the components of
comprehensive income in a separate but consecutive statement.
Testing Goodwill for Impairment
Effective January 1, 2012, the Corporation adopted the
amendments to ASC Topic 350, Goodwill. The amended standard allows
entities testing goodwill for impairment to have the option of
performing a qualitative assessment before calculating the fair
value of the reporting unit. If the qualitative factors indicate
that the fair value of the reporting unit is more likely than not
(i.e., greater than a 50% chance) to be greater than the carrying
value, then the two-step impairment test, including the
quantification of the fair value of the reporting unit, would not
be required. In adopting the amendments, Fortis will perform a
qualitative assessment before calculating the fair value of its
reporting units when it performs its annual impairment test as of
October 1.
Fair Value Measurement
Effective January 1, 2012, the Corporation adopted the
amendments to ASC Topic 820, Fair Value Measurements and
Disclosures. The amended standard improves comparability of fair
value measurements presented and disclosed in financial statements
prepared in accordance with US GAAP. The amendment does not change
what items are measured at fair value but instead makes various
changes to the guidance pertaining to how fair value is measured.
The above-noted changes did not materially impact the Corporation's
interim consolidated financial statements for the three and nine
months ended September 30, 2012.
New Accounting Policies
Effective January 1, 2012, the FortisBC Energy companies
prospectively adopted the policy of accruing for non-asset
retirement obligation ("non-ARO") removal costs in depreciation
expense, as requested in their 2012-2013 Revenue Requirements
Application ("RRA") and subsequently approved by the regulator in
its April 2012 decision. The accrual of estimated non-ARO removal
costs is included in depreciation expense and the provision balance
is recognized as a long-term regulatory liability. Actual non-ARO
removal costs, net of salvage proceeds, are recorded against the
regulatory liability when incurred. Non-ARO removal costs are
direct costs incurred by the FortisBC Energy companies in taking
assets out of service, whether through actual removal of the assets
or through disconnection of the assets from the transmission or
distribution system. Prior to 2012 estimated non-ARO removal costs,
net of salvage proceeds, were recognized in operating expenses with
variances between actual non-ARO removal costs and those forecasted
for rate-setting purposes recorded in a regulatory deferral account
for future recovery from, or refund to, customers in rates
commencing in 2012. For the three and nine months ended September
30, 2012, non-ARO removal costs of approximately $5 million and $15
million, respectively, were accrued as part of depreciation
expense. For the three and nine months ended September 30, 2011,
non-ARO removal costs of approximately $4 million and $12 million,
respectively, were recognized in operating expenses.
Prior to 2012 variances from forecast, adjusted for certain
revenue and cost variances which flowed through to customers, for
rate-setting purposes were shared equally between customers and
FortisBC Electric. As applied for in FortisBC Electric's 2012-2013
RRA and approved by the regulator, prospectively from January 1,
2012 the above-noted sharing of positive or negative variances is
no longer in effect. Beginning in 2012, variances between actual
electricity revenue and purchased power costs and those forecasted
in determining customer electricity rates are subject to full
deferral account treatment, to be recovered from, or refunded to,
customers in future rates and, therefore, do not impact net
earnings in 2012. Effective January 1, 2012, however, the flow
through treatment for finance charges, as was applied for in
FortisBC Electric's 2012-2013 RRA, was denied by the regulator
pursuant to its revenue requirements decision. As a result, a
retroactive adjustment was recorded in the third quarter of 2012 to
eliminate the flow through treatment. Variances between actual
finance charges from those forecasted in determining customer
electricity rates, therefore, have an impact on net earnings in
2012.
Effective January 1, 2012, as approved by the regulator, the
FortisBC Energy companies are deferring variances between actual
depreciation expense and that forecasted in determining customer
gas rates.
Effective January 1, 2012, as approved by the regulator,
FortisAlberta is no longer permitted to defer transmission volume
variances associated with its Alberta Electric System Operator
("AESO") charges deferral account. For the three and nine months
ended September 30, 2012, FortisAlberta recognized approximately
$3.5 million and $6.5 million, respectively, of net transmission
revenue as a result of this change.
Change in Estimates - Capital Asset Depreciation
Changes in regulator-approved depreciation rates at
FortisAlberta and FortisBC Electric, in conjunction with approved
depreciation studies and revenue requirements decisions received in
2012, have impacted consolidated depreciation expense. The
composite depreciation rate for utility capital assets at
FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011.
FortisBC Electric's composite depreciation rate for utility capital
assets decreased to 3.1% for 2012 from 3.2% for 2011. As required
by the regulator, effective January 1, 2012, depreciation rates at
the FortisBC Energy companies now include an amount allowed for
regulatory purposes to accrue for estimated non-ARO removal costs,
net of salvage proceeds. The impact of the above-noted changes in
depreciation rates on depreciation expense has been reflected in
the utilities' approved revenue requirements and resulting customer
rates.
3. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities
is provided below. A detailed description of the nature of the
Corporation's regulatory assets and liabilities is provided in Note
7 to the Corporation's 2011 US GAAP annual audited consolidated
financial statements.
As at
September 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes 683 630
Employee future benefits 406 428
Deferred lease costs - FortisBC Electric 81 70
Rate stabilization accounts - electric
utilities 53 55
Replacement energy deferral - Point Lepreau
(1) 47 47
Deferred energy management costs 43 36
Rate stabilization accounts - FortisBC Energy
companies 31 105
Deferred operating overhead costs 30 22
Customer Care Enhancement Project cost
deferral 25 13
Deferred net losses on disposal of utility
capital assets 25 23
Income taxes recoverable on other post-
employment benefit ("OPEB") plans 23 22
Whistler pipeline contribution deferral 16 16
Pension cost variance deferral 14 10
Alternative energy projects cost deferral 13 8
Deferred development costs for capital 10 11
Deferred costs - smart meters 8 8
AESO charges deferral - 44
Other regulatory assets 83 71
----------------------------------------------------------------------------
Total regulatory assets 1,591 1,619
Less: current portion (98) (219)
----------------------------------------------------------------------------
Long-term regulatory assets 1,493 1,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
September 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Regulatory liabilities
Non-ARO removal cost provision 374 354
Rate stabilization accounts - FortisBC Energy
companies 154 127
Rate stabilization accounts - electric
utilities 36 33
AESO charges deferral 33 12
Deferred income taxes 15 9
Deferred interest 8 10
Performance-based rate-setting incentive
liabilities 8 7
Income tax variance deferral 6 12
Southern Crossing Pipeline deferral 5 8
Unrecognized net gains on disposal of utility
capital assets - 6
Other regulatory liabilities 24 20
----------------------------------------------------------------------------
Total regulatory liabilities 663 598
Less: current portion (75) (43)
----------------------------------------------------------------------------
Long-term regulatory liabilities 588 555
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
September 30, 2012 September 30, 2012
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning
of period 189,967 3,071 188,828 3,036
Dividend
Reinvestment
Plan 460 15 1,355 43
Consumer Share
Purchase Plan 8 - 32 1
Employee Share
Purchase Plan 63 2 63 2
Stock Option
Plans 160 4 380 10
----------------------------------------------------------------------------
Balance, end of
period 190,658 3,092 190,658 3,092
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effective May 4, 2012, the Corporation's Board of Directors
approved the 2012 Employee Share Purchase Plan ("2012 ESPP"). Under
the 2012 ESPP, common shares may be issued from treasury, acquired
in the open market or a combination from treasury and the open
market, as determined by the Corporation. The first shares issued
from treasury under the 2012 ESPP occurred in September 2012.
Subscription Receipts Offering
In June 2012, to finance a portion of the pending acquisition of
CH Energy Group, Fortis sold 18,500,000 Subscription Receipts at
$32.50 each through a bought-deal offering underwritten by a
syndicate of underwriters led by CIBC World Markets Inc., Scotia
Capital Inc. and TD Securities Inc., realizing gross proceeds of
approximately $601 million. The gross proceeds from the sale of the
Subscription Receipts are being held by an escrow agent, pending
satisfaction of closing conditions, including receipt of regulatory
approvals, included in the agreement to acquire CH Energy Group
("Release Conditions"). The Subscription Receipts began trading on
the Toronto Stock Exchange on June 27, 2012 under the symbol
"FTS.R".
Each Subscription Receipt will entitle the holder thereof to
receive, on satisfaction of the Release Conditions, and without
payment of additional consideration, one common share of Fortis and
a cash payment equal to the dividends declared on Fortis common
shares to holders of record during the period from June 27, 2012 to
the date of issuance of the common shares in respect of the
Subscription Receipts.
If the Release Conditions are not satisfied by June 30, 2013, or
if the agreement and plan of merger relating to the acquisition of
CH Energy Group is terminated prior to such time, holders of
Subscription Receipts shall be entitled to receive from the escrow
agent an amount equal to the full subscription price thereof plus
their pro rata share of the interest earned on such amount (Note
18).
5. NON-CONTROLLING INTERESTS
As at
September 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Waneta Expansion Limited Partnership ("Waneta
Partnership") 197 128
Caribbean Utilities 72 73
Mount Hayes Limited Partnership (Note 18) 12 -
Preference shares of Newfoundland Power 7 7
----------------------------------------------------------------------------
288 208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. STOCK-BASED COMPENSATION PLANS
In January 2012 21,417 Deferred Share Units ("DSUs") were
granted to the Corporation's Board of Directors, representing the
equity component of the Directors' annual compensation and, where
opted, their annual retainers in lieu of cash. Each DSU represents
a unit with an underlying value equivalent to the value of one
common share of the Corporation.
In March 2012 44,863 Performance Share Units ("PSUs") were paid
out to the President and Chief Executive Officer ("CEO") of the
Corporation at $32.40 per PSU, for a total of approximately $1.5
million. The payout was made upon the three-year maturation period
in respect of the PSU grant made in March 2009 and the President
and CEO satisfying the payment requirements, as determined by the
Human Resources Committee of the Board of Directors of Fortis.
In May 2012 62,000 PSUs were granted to the President and CEO of
the Corporation. Each PSU represents a unit with an underlying
value equivalent to the value of one common share of the
Corporation. The maturation period of the May 2012 PSU grant is
three years, at which time a cash payment may be made to the
President and CEO after evaluation by the Human Resources Committee
of the Board of Directors of the achievement of payment
requirements.
In May 2012 the 2012 Stock Option Plan ("2012 Plan") was
approved at the Annual General Meeting of the Corporation's
shareholders. The 2012 Plan will ultimately replace the 2002 Stock
Option Plan ("2002 Plan") and the 2006 Stock Option Plan ("2006
Plan"). The 2002 Plan and 2006 Plan will cease to exist when all
outstanding options are exercised or expire in or before 2016 and
2018, respectively. The Corporation has ceased the granting of
options under the 2002 Plan and 2006 Plan and all new options
granted after 2011 will be made under the 2012 Plan.
In May 2012 the Corporation granted 789,220 options to purchase
common shares under its 2012 Plan at the five-day volume weighted
average trading price immediately preceding the date of grant of
$34.27. The options vest evenly over a four-year period on each
anniversary of the date of grant. The options expire 10 years after
the date of grant. The fair value of each option granted was $4.21
per option.
The fair value was estimated at the date of grant using the
Black-Scholes fair value option-pricing model and the following
assumptions:
Dividend yield (%) 3.67
Expected volatility (%) 22.2
Risk-free interest rate (%) 1.50
Weighted average expected life (years) 5.3
For the three and nine months ended September 30, 2012,
stock-based compensation expense of approximately $2 million and $5
million, respectively, was recognized ($2 million and $5 million
for the three and nine months ended September 30, 2011,
respectively).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a
combination of defined benefit pension plans and defined
contribution pension plans, including group registered retirement
savings plans, for employees. The Corporation and certain
subsidiaries also offer OPEB plans for qualifying employees. The
net benefit cost of providing the defined benefit pension and OPEB
plans is detailed in the following tables.
Quarter Ended September 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 6 5 2 1
Interest costs 12 12 2 3
Expected return on plan
assets (12) (12) - -
Amortization of actuarial
losses 6 5 2 1
Amortization of past service
costs/plan amendments - - - (1)
Regulatory adjustments (2) (2) - 1
----------------------------------------------------------------------------
Net benefit cost 10 8 6 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date September 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 20 15 5 3
Interest costs 35 36 8 9
Expected return on plan
assets (37) (36) - -
Amortization of actuarial
losses 19 15 4 3
Amortization of past service
costs/plan amendments - - (2) (3)
Amortization of transitional
obligation 1 - 1 -
Regulatory adjustments (8) (6) 1 3
----------------------------------------------------------------------------
Net benefit cost 30 24 17 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three and nine months ended September 30, 2012, the
Corporation expensed $3 million and $10 million, respectively ($3
million and $11 million for the three and nine months ended
September 30, 2011, respectively) related to defined contribution
pension plans.
8. OTHER INCOME (EXPENSES), NET
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Interest income 2 2 4 4
Equity component of
allowance for funds used
during construction 1 2 4 10
Foreign exchange (loss) gain (2) 1 (2) 1
Acquisition-related expenses - - (8) -
Merger termination fee - 17 - 17
Other income, net of
expenses - - - 2
----------------------------------------------------------------------------
1 22 (2) 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The foreign exchange loss for the three and nine months ended
September 30, 2012 included approximately $3 million and $2.5
million, respectively, related to the translation of the
Corporation's US dollar-denominated long-term other asset
representing the book value of the Corporation's expropriated
investment in Belize Electricity (Notes 17 and 19).
The foreign exchange gain for the three and nine months ended
September 30, 2011 included a foreign exchange gain of $7 million
associated with the translation of the above-noted US
dollar-denominated long-term other asset, which was partially
offset by a $5.5 million ($4.5 million after tax) foreign exchange
loss associated with the translation of previously hedged US
dollar-denominated long-term debt.
The acquisition-related expenses are associated with the pending
acquisition of CH Energy Group (Notes 1 and 18).
The termination fee was paid to Fortis in July 2011 following
the termination of a Merger Agreement between Fortis and Central
Vermont Public Service Corporation.
9. FINANCE CHARGES
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Interest:
Long-term debt and finance
and capital lease
obligations 95 91 282 275
Short-term borrowings and
other finance charges 3 1 6 10
Debt component of allowance
for funds used during
construction (5) (3) (12) (11)
----------------------------------------------------------------------------
93 89 276 274
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. INCOME TAXES
Income taxes differ from the amount that would be expected to be
generated by applying the enacted combined Canadian federal and
provincial statutory income tax rate to earnings before income
taxes. The following is a reconciliation of consolidated statutory
income taxes to consolidated effective income taxes.
Quarter Ended Year-to-Date
September 30 September 30
($ millions, except as noted) 2012 2011 2012 2011
----------------------------------------------------------------------------
Combined Canadian federal and
provincial statutory income tax
rate 29.0% 30.5% 29.0% 30.5%
----------------------------------------------------------------------------
Statutory income tax rate applied to
earnings before income taxes 19 25 91 100
Difference between Canadian
statutory income tax rate and rates
applicable to foreign subsidiaries (3) (4) (10) (9)
Difference in Canadian provincial
statutory income tax rates
applicable to subsidiaries in
different Canadian jurisdictions (1) (1) (9) (9)
Items capitalized for accounting
purposes but expensed for income
tax purposes (11) (11) (39) (39)
Difference between capital cost
allowance and amounts claimed for
accounting purposes 3 5 7 11
Non-deductible expenses 2 2 5 3
Part VI.1 tax - difference between
enacted and substantively enacted
tax rates and the effect of
statute-barred reversals (1) - 2 2
Difference between employee future
benefits paid and amounts expensed
for accounting purposes - (1) 1 (1)
Other (1) (3) (4) 1
----------------------------------------------------------------------------
Income taxes 7 12 44 59
----------------------------------------------------------------------------
Effective income tax rate 10.6% 14.6% 14.1% 17.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2012, the Corporation had approximately $100
million (December 31, 2011 - $86 million) in non-capital and
capital loss carryforwards, of which $8 million (December 31, 2011
- $13 million) has not been recognized in the consolidated
financial statements. The non-capital loss carryforwards expire
between 2014 and 2032.
11. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on
the weighted average number of common shares outstanding. Diluted
EPS is calculated using the treasury stock method for options and
the "if-converted" method for convertible securities.
EPS were as follows:
Quarter Ended September 30
2012 2011
--------------------------------------------------------
Earnings Earnings
to Common Weighted to Common Weighted
Share- Average Share- Average
holders Shares holders Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
--------------------------------------------------------------------------
Basic EPS 45 190.2 $ 0.24 56 186.5 $ 0.30
Effect of
potential
dilutive
securities:
Stock Options - 0.9 - 1.0
Preference
Shares 4 10.3 4 10.1
Convertible
Debentures - - 1 1.4
--------------------------------------------------------------------------
49 201.4 61 199.0
Deduct anti-
dilutive impacts:
Preference
Shares (4) (10.3) (4) (10.1)
Convertible
Debentures - - (1) (1.4)
--------------------------------------------------------------------------
Diluted EPS 45 191.1 $ 0.24 56 187.5 $ 0.30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date September 30
2012 2011
--------------------------------------------------------
Earnings Earnings
to Common Weighted to Common Weighted
Share- Average Share- Average
holders Shares holders Shares
($ (in ($ (in
millions) millions) EPS millions) millions) EPS
--------------------------------------------------------------------------
Basic EPS 228 189.6 $ 1.20 229 179.5 $ 1.28
Effect of
potential
dilutive
securities:
Stock Options - 0.9 - 1.0
Preference
Shares 12 10.3 12 10.1
Convertible
Debentures - - 2 1.4
--------------------------------------------------------------------------
240 200.8 243 192.0
Deduct anti-
dilutive impacts:
Preference
Shares (5) (3.9) (5) (3.9)
--------------------------------------------------------------------------
Diluted EPS 235 196.9 $ 1.19 238 188.1 $ 1.27
--------------------------------------------------------------------------
--------------------------------------------------------------------------
12. BUSINESS ACQUISITIONS
In April 2012 FortisOntario exercised its option, under the
terms of a 10-year operating lease agreement with the City of Port
Colborne that commenced in April 2002, to purchase the remaining
assets of Port Colborne Hydro for approximately $7 million. Under
the lease arrangement with the City of Port Colborne, and now
through ownership of the previously leased assets, FortisOntario
operates and maintains the City of Port Colborne's electricity
distribution system for provision of electricity service to the
residents of Port Colborne. Throughout the 10-year lease term,
FortisOntario incurred approximately $17 million in capital
expenditures in Port Colborne Hydro's electricity distribution
system. The exercise of the purchase option, which qualifies as a
business combination, provides ownership and legal title to all of
the assets, including equipment, real property and distribution
assets, which constitute the entire distribution system in Port
Colborne. The purchase was approved by the Ontario Energy
Board.
FortisOntario is regulated under traditional cost of service and
the determination of revenue and earnings is based on a regulated
rate of return that is applied to historic values which do not
change with a change of ownership. Therefore, fair market value
approximates book value and no adjustments were recorded for the
assets acquired, because all of the economic benefits and
obligations associated with them beyond regulated rates of return
accrue to the customers. Accordingly, $3 million of the purchase
price was allocated to utility capital assets and $4 million was
recognized as goodwill in the preliminary purchase price
allocation.
In August 2012 Fortis Turks and Caicos acquired TCU for an
aggregate purchase price of approximately $13 million (US$13
million), inclusive of debt assumed of $5 million (US$5 million).
TCU is a regulated electric utility operating pursuant to a 50-year
licence expiring in 2036. The utility serves more than 2,000
residential and commercial customers between Grand Turk and Salt
Cay with a diesel-fired generating capacity of 9 MW. Fortis Turks
and Caicos is regulated under traditional cost of service and the
determination of revenue and earnings is based on a regulated rate
of return that is applied to historic values which do not change
with a change of ownership. Therefore, fair market value
approximates book value and no adjustments were recorded for the
net assets acquired, because all of the economic benefits and
obligations associated with them beyond regulated rates of return
accrue to the customers. Accordingly, approximately $9 million of
the purchase price was allocated to utility capital assets, $3
million to current net assets, $5 million to long-term debt and $1
million was recognized as goodwill in the preliminary purchase
price allocation.
13. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
------------------------------------------------------------
Gas
Utilities Electric Utilities
------------------------------------------------------------
FortisBC
Quarter Ended Energy New- Total
September 30, Companies found- Other Electric Electric
2012 - Fortis FortisBC land Cana- Cana- Carib-
($ millions) Canadian Alberta Electric Power dian dian bean
----------------------------------------------------------------------------
Revenue 192 117 71 100 91 379 72
Energy supply
costs 61 - 16 54 59 129 45
Operating
expenses 64 40 20 17 11 88 7
Depreciation and
amortization 40 34 12 11 7 64 8
----------------------------------------------------------------------------
Operating income 27 43 23 18 14 98 12
Other income
(expenses), net 1 - 1 1 - 2 1
Finance charges 36 17 9 9 5 40 3
Income tax
(recovery)
expense (2) - 2 1 3 6 -
----------------------------------------------------------------------------
Net (loss)
earnings (6) 26 13 9 6 54 10
Non-controlling
interests - - - - - - 3
Preference share
dividends - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders (6) 26 13 9 6 54 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 67 515 138
Identifiable
assets 4,503 2,617 1,686 1,244 705 6,252 735
----------------------------------------------------------------------------
Total assets 5,416 2,844 1,907 1,244 772 6,767 873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 66 104 19 22 13 158 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
September 30,
2011($
millions)
----------------------------------------------------------------------------
Revenue 197 103 67 101 87 358 74
Energy supply
costs 76 - 15 52 56 123 47
Operating
expenses 65 35 19 17 11 82 9
Depreciation and
amortization 29 34 11 11 6 62 7
----------------------------------------------------------------------------
Operating income 27 34 22 21 14 91 11
Other income
(expenses), net 2 - - - - - -
Finance charges 36 15 10 9 5 39 2
Income tax
(recovery)
expense (3) - 2 4 3 9 -
----------------------------------------------------------------------------
Net (loss)
earnings (4) 19 10 8 6 43 9
Non-controlling
interests - - - - - - 3
Preference share
dividends - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders (4) 19 10 8 6 43 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 144
Identifiable
assets 4,364 2,345 1,626 1,232 670 5,873 742
----------------------------------------------------------------------------
Total assets 5,277 2,572 1,847 1,232 733 6,384 886
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 64 82 25 24 14 145 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
----------------------------------
Quarter Ended Inter-
September 30, Fortis Fortis segment
2012 Gene- Proper- Corporate elimi- Conso-
($ millions) ration ties and Other nations lidated
----------------------------------------------------------------------------
Revenue 8 65 5 (7) 714
Energy supply
costs - - - - 235
Operating
expenses 2 42 2 (2) 203
Depreciation and
amortization 1 5 - - 118
----------------------------------------------------------------------------
Operating income 5 18 3 (5) 158
Other income
(expenses), net - - (3) - 1
Finance charges - 6 13 (5) 93
Income tax
(recovery)
expense - 4 (1) - 7
----------------------------------------------------------------------------
Net (loss)
earnings 5 8 (12) - 59
Non-controlling
interests - - - - 3
Preference share
dividends - - 11 - 11
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders 5 8 (23) - 45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,566
Identifiable
assets 686 623 498 (425) 12,872
----------------------------------------------------------------------------
Total assets 686 623 498 (425) 14,438
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 39 9 - - 283
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
September 30,
2011($
millions)
----------------------------------------------------------------------------
Revenue 11 63 4 (8) 699
Energy supply
costs - - - - 246
Operating
expenses 2 40 4 (2) 200
Depreciation and
amortization 1 5 - - 104
----------------------------------------------------------------------------
Operating income 8 18 - (6) 149
Other income
(expenses), net - - 20 - 22
Finance charges - 6 12 (6) 89
Income tax
(recovery)
expense - 3 3 - 12
----------------------------------------------------------------------------
Net (loss)
earnings 8 9 5 - 70
Non-controlling
interests - - - - 3
Preference share
dividends - - 11 - 11
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders 8 9 (6) - 56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,568
Identifiable
assets 539 589 507 (434) 12,180
----------------------------------------------------------------------------
Total assets 539 589 507 (434) 13,748
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 49 11 - - 286
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital
assets, including amounts for AESO transmission-related capital
projects, income producing properties and intangible assets, as
reflected on the consolidated statements of cash flows
REGULATED
------------------------------------------------------------
Gas
Utilities Electric Utilities
------------------------------------------------------------
FortisBC
Year-to-Date Energy New- Total
September 30, Companies found- Other Electric Electric
2012 - Fortis FortisBC land Cana- Cana- Carib-
($ millions) Canadian Alberta Electric Power dian dian bean
----------------------------------------------------------------------------
Revenue 1,004 335 225 422 264 1,246 202
Energy supply
costs 472 - 54 274 168 496 124
Operating
expenses 197 116 62 54 35 267 24
Depreciation and
amortization 120 99 36 33 20 188 24
----------------------------------------------------------------------------
Operating income 215 120 73 61 41 295 30
Other income
(expenses), net 2 2 1 2 - 5 2
Finance charges 107 49 29 27 16 121 10
Income tax
expense
(recovery) 20 - 7 8 7 22 -
----------------------------------------------------------------------------
Net earnings
(loss) 90 73 38 28 18 157 22
Non-controlling
interests 1 - - - - - 6
Preference share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 89 73 38 28 18 157 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 67 515 138
Identifiable
assets 4,503 2,617 1,686 1,244 705 6,252 735
----------------------------------------------------------------------------
Total assets 5,416 2,844 1,907 1,244 772 6,767 873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 144 304 52 58 35 449 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
September 30,
2011($
millions)
----------------------------------------------------------------------------
Revenue 1,090 306 215 417 256 1,194 234
Energy supply
costs 590 - 49 266 163 478 146
Operating
expenses 209 106 58 54 34 252 31
Depreciation and
amortization 83 100 34 32 18 184 24
----------------------------------------------------------------------------
Operating income 208 100 74 65 41 280 33
Other income
(expenses), net 8 3 1 - - 4 2
Finance charges 106 44 29 27 16 116 11
Income tax
expense
(recovery) 24 1 8 14 7 30 1
----------------------------------------------------------------------------
Net earnings
(loss) 86 58 38 24 18 138 23
Non-controlling
interests - - - - - - 7
Preference share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 86 58 38 24 18 138 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 144
Identifiable
assets 4,364 2,345 1,626 1,232 670 5,873 742
----------------------------------------------------------------------------
Total assets 5,277 2,572 1,847 1,232 733 6,384 886
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 177 253 78 55 33 419 57
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
----------------------------------
Year-to-Date Inter-
September 30, Fortis Fortis segment
2012 Gene- Proper- Corporate elimi- Conso-
($ millions) ration ties and Other nations lidated
--------------------------------------------------------------------------
Revenue 26 181 18 (22) 2,655
Energy supply
costs 1 - - (1) 1,092
Operating
expenses 6 124 8 (5) 621
Depreciation and
amortization 3 15 1 - 351
--------------------------------------------------------------------------
Operating income 16 42 9 (16) 591
Other income
(expenses), net 1 - (11) (1) (2)
Finance charges 1 18 36 (17) 276
Income tax
expense
(recovery) 1 7 (6) - 44
--------------------------------------------------------------------------
Net earnings
(loss) 15 17 (32) - 269
Non-controlling
interests - - - - 7
Preference share
dividends - - 34 - 34
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 15 17 (66) - 228
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,566
Identifiable
assets 686 623 498 (425) 12,872
--------------------------------------------------------------------------
Total assets 686 623 498 (425) 14,438
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(1) 144 24 - - 794
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-Date
September 30,
2011($
millions)
--------------------------------------------------------------------------
Revenue 25 173 17 (29) 2,704
Energy supply
costs 1 - - (8) 1,207
Operating
expenses 6 117 9 (5) 619
Depreciation and
amortization 3 14 1 - 309
--------------------------------------------------------------------------
Operating income 15 42 7 (16) 569
Other income
(expenses), net 1 - 20 (1) 34
Finance charges 2 18 38 (17) 274
Income tax
expense
(recovery) 1 6 (3) - 59
--------------------------------------------------------------------------
Net earnings
(loss) 13 18 (8) - 270
Non-controlling
interests - - - - 7
Preference share
dividends - - 34 - 34
--------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 13 18 (42) - 229
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,568
Identifiable
assets 539 589 507 (434) 12,180
--------------------------------------------------------------------------
Total assets 539 589 507 (434) 13,748
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(1) 131 20 - - 804
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital
assets, including amounts for AESO transmission-related capital
projects, income producing properties and intangible assets, as
reflected on the consolidated statements of cash flows
Related party transactions are in the normal course of
operations and are measured at the exchange amount, which is the
amount of consideration established and agreed to by the related
parties. The significant related party inter-segment transactions
primarily related to: (i) the sale of energy from Fortis Generation
to Belize Electricity, up to June 20, 2011; (ii) electricity sales
from Newfoundland Power to Fortis Properties; and (iii) finance
charges on related party borrowings. The significant related party
inter-segment transactions for the three and nine months ended
September 30, 2012 and 2011 were as follows:
Significant Inter-Segment
Transactions Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities -
Caribbean - - - 7
Sales from Fortis Generation to
Other Canadian Electric Utilities - - - 1
Sales from Newfoundland Power to
Fortis Properties 1 1 4 3
Inter-segment finance charges on
lending from:
Fortis Generation to Other
Canadian Electric Utilities - - 1 1
Corporate to Regulated Electric
Utilities - Canadian - 1 - 2
Corporate to Regulated Electric
Utilities - Caribbean 1 1 3 3
Corporate to Fortis Generation - 1 1 2
Corporate to Fortis Properties 4 3 12 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at September 30
($ millions) 2012 2011
----------------------------------------------------------------------------
Inter-segment lending from:
Fortis Generation to Other
Canadian Electric Utilities 20 20
Corporate to Regulated Electric
Utilities - Canadian - 50
Corporate to Regulated Electric
Utilities - Caribbean 84 78
Corporate to Fortis Generation 12 32
Corporate to Fortis Properties 284 226
Other inter-segment assets 25 28
----------------------------------------------------------------------------
Total inter-segment eliminations 425 434
----------------------------------------------------------------------------
----------------------------------------------------------------------------
14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH
FLOWS
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash paid for:
Interest 84 79 269 260
Income taxes 12 16 63 61
Change in non-cash operating working
capital:
Accounts receivable 96 115 224 184
Prepaid expenses (8) (8) (14) (15)
Inventories (48) (84) (21) (28)
Regulatory assets - current portion 2 (15) 50 (21)
Accounts payable and other current
liabilities 28 4 (39) (34)
Regulatory liabilities - current
portion (13) (14) 19 18
----------------------------------------------------------------------------
57 (2) 219 104
----------------------------------------
----------------------------------------
Non-cash investing and financing
activities:
Common share dividends reinvested 15 16 43 47
Exercise of stock options into
common shares - - 1 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
15. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation generally limits the use of derivative
instruments to those that qualify as accounting or economic hedges.
As at September 30, 2012, the Corporation's derivative contracts
consisted of fuel option contracts, natural gas swap and option
contracts, and gas purchase contract premiums. The fuel option
contracts are held by Caribbean Utilities and the remaining
derivative instruments are held by the FortisBC Energy
companies.
Volume of Derivative Activity
As at September 30, 2012, the following notional volumes related
to fuel option contracts and natural gas derivatives that are
expected to be settled are outlined below.
2012 2013 2014
----------------------------------------------------------------------------
Fuel option contracts (millions of
imperial gallons) 4 3 -
Gas swaps and options (petajoules) 4 26 6
Gas purchase contract premiums
(petajoules) 94 17 1
----------------------------------------------------------------------------
Presentation of Derivative Instruments in the Consolidated
Financial Statements
In the Corporation's consolidated balance sheets, derivative
instruments are presented on a net basis by counterparty, where the
right of offset exists.
The Corporation's outstanding derivative balances were as
follows:
As at
September 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Gross derivatives balance (1) 59 136
Netting (2) - -
Cash collateral - -
----------------------------------------------------------------------------
Total derivative balances (3) 59 136
------------------------------
------------------------------
(1) Refer to Note 16 for a discussion of the valuation techniques used to
calculate the fair value of the derivative instruments.
(2) Positions, by counterparty, are netted where the intent and legal right
to offset exists.
(3) Unrealized losses of $34 million on commodity risk-related derivative
instruments as at September 30, 2012 were recognized in current
regulatory assets and $25 million were recognized as an offset to
current regulatory liabilities (December 31, 2011 - $136 million
recognized in current regulatory assets), which would otherwise be
recognized on the consolidated statement of comprehensive income and in
accumulated other comprehensive loss. These amounts exclude the impact
of cash collateral postings.
Cash flows associated with the settlement of all derivative
instruments are included in operating cash flows on the
Corporation's consolidated statements of cash flows.
The majority of the FortisBC Energy companies' risk-related
derivative instruments contain collateral posting provisions tied
to FEI's credit rating. A downgrade of FEI below investment grade
by any of the major credit rating agencies could trigger margin
calls and other cash requirements under FEI's gas purchase and swap
and option contracts. Most of the existing natural gas derivative
contracts are in liability positions and might be subject to margin
calls and other cash requirements if FEI was downgraded below
investment grade.
16. FAIR VALUE MEASUREMENTS
Fair value is the price at which a market participant could sell
an asset or transfer a liability to an unrelated party. A fair
value measurement is required to reflect the assumptions that
market participants would use in pricing an asset or liability
based on the best available information. These assumptions include
the risks inherent in a particular valuation technique, such as a
pricing model, and the risks inherent in the inputs to the model. A
fair value hierarchy exists that prioritizes the inputs used to
measure fair value. The Corporation is required to record all
derivative instruments at fair value except for those which qualify
for the normal purchase and normal sale exception.
The three levels of the fair value hierarchy are defined as
follows:
Level 1: Fair value determined using unadjusted quoted prices in active
markets
Level 2: Fair value determined using pricing inputs that are observable
Level 3: Fair value determined using unobservable inputs only when relevant
observable inputs are not available
The fair values of the Corporation's financial instruments,
including derivatives, reflect point-in-time estimates based on
current and relevant market information about the instruments as at
the balance sheet dates. The estimates cannot be determined with
precision as they involve uncertainties and matters of judgment
and, therefore, may not be relevant in predicting the Corporation's
future consolidated earnings or cash flows.
The following table details the estimated fair value
measurements of the Corporation's financial instruments, all of
which were measured using Level 2 inputs, except for certain
long-term debt as noted.
As at
Asset (Liability) September 30, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
Other asset - Belize
Electricity (1) 103 - (2) 106 - (2)
Long-term debt, including
current portion (3) (5,937) (7,476) (5,788) (7,172)
Waneta Partnership
promissory note (4) (46) (52) (45) (49)
Foreign exchange forward
contract (5) - - - -
Fuel option contracts (5) - - (1) (1)
Natural gas derivatives: (5)
Swaps and options (60) (60) (135) (135)
Gas purchase contract
premiums 1 1 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in long-term other assets on the consolidated balance sheet
(2) The fair value of the Corporation's expropriated investment in Belize
Electricity determined under the GOB's valuation is significantly lower
than the fair value determined under the Corporation's independent
valuation of the utility. Due to uncertainty in the ultimate amount and
ability of the GOB to pay appropriate fair value compensation owing to
Fortis for the expropriation of Belize Electricity, the Corporation has
recorded the long-term other asset at the carrying value of the
Corporation's previous investment in Belize Electricity, including
foreign exchange impacts (Notes 17 and 19).
(3) The Corporation's $200 million unsecured debentures due 2039 and
consolidated credit facilities classified as long-term are valued using
Level 1 inputs. All other long-term debt is valued using Level 2
inputs.
(4) Included in long-term other liabilities on the consolidated balance
sheet
(5) The fair values of the derivatives were recorded in accounts payable
and other current liabilities as at September 30, 2012 and December 31,
2011. The fair value of the fuel option contracts as at September 30,
2012 were less than $1 million. The foreign exchange forward contract
held by FEI expired in April 2012. The fair value of the contract was
less than $1 million as at December 31, 2011.
The fair value of long-term debt is calculated using quoted
market prices when available. When quoted market prices are not
available, the fair value is determined by discounting the future
cash flows of the specific debt instrument at an estimated yield to
maturity equivalent to benchmark government bonds or treasury
bills, with similar terms to maturity, plus a credit risk premium
equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt or
promissory note prior to maturity, the fair value estimate does not
represent an actual liability and, therefore, does not include
exchange or settlement costs.
The fuel option contracts are used by Caribbean Utilities to
reduce the impact of volatility in fuel prices on customer rates,
as approved by the regulator under the Company's Fuel Price
Volatility Management Program. The fair value of the fuel option
contracts reflects only the value of the heating oil derivative and
not the offsetting change in the value of the underlying future
purchases of heating oil and is calculated using published market
prices for heating oil. The fuel option contracts mature in March
2013. In October 2012 Caribbean Utilities executed additional fuel
option contracts covering the period from November 1, 2012 to
October 31, 2013. With the execution of these new contracts,
approximately 70% of the Company's annual diesel fuel requirements
are under fuel hedging arrangements.
The natural gas derivatives are used to fix the effective
purchase price of natural gas, as the majority of the natural gas
supply contracts at the FortisBC Energy companies have floating,
rather than fixed, prices. The fair value of the natural gas
derivatives was calculated using the present value of cash flows
based on market prices and forward curves for the commodity cost of
natural gas.
The fair values of the fuel option contracts and natural gas
derivatives were estimates of the amounts that the utilities would
have to receive or pay to terminate the outstanding contracts as at
the balance sheet dates. As at September 30, 2012, none of the fuel
option contracts or natural gas derivatives were designated as
hedges of fuel purchases or natural gas supply contracts. However,
any gains or losses associated with changes in the fair value of
the derivatives were deferred as a regulatory asset or liability
for recovery from, or refund to, customers in future rates, as
permitted by the regulators.
17. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity
risk and market risk as a result of holding financial instruments
in the normal course of business.
Credit Risk Risk that a counterparty to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.
Liquidity Risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market Risk Risk that the fair value or future cash flows of a
financial instrument will fluctuate due to changes in
market prices. The Corporation is exposed to foreign
exchange risk, interest rate risk and commodity price
risk.
Credit Risk
For cash equivalents, trade and other accounts receivable, and
other long-term receivables, the Corporation's credit risk is
limited to the carrying value on the consolidated balance sheet.
The Corporation generally has a large and diversified customer
base, which minimizes the concentration of credit risk. The
Corporation and its subsidiaries have various policies to minimize
credit risk, which include requiring customer deposits, prepayments
and/or credit checks for certain customers and performing
disconnections and/or using third-party collection agencies for
overdue accounts.
FortisAlberta has a concentration of credit risk as a result of
its distribution service billings being to a relatively small group
of retailers. As at September 30, 2012, the utility's gross credit
risk exposure was approximately $57 million, representing the
projected value of retailer billings over a 37-day period. The
Company has reduced its exposure to less than $1 million by
obtaining from the retailers an acceptable form of prudential,
which includes either a cash deposit, bond, letter of credit or an
investment-grade credit rating from a major rating agency, or by
having the retailer obtain a financial guarantee from an entity
with an investment-grade credit rating.
The FortisBC Energy companies are exposed to credit risk in the
event of non-performance by counterparties to derivative financial
instruments. To help mitigate credit risk, the FortisBC Energy
companies deal with reasonable credit-quality institutions in
accordance with established credit-approval practices. The FortisBC
Energy companies do not expect any counterparties to fail to meet
their obligations. The counterparties with which the FortisBC
Energy companies have significant derivative transactions are
A-rated entities or better. The Company uses netting arrangements
to reduce credit risk and net settles payments with counterparties
where net settlement provisions exist.
The following table summarizes the FortisBC Energy companies'
net credit risk exposure to its counterparties, as well as credit
risk exposure to counterparties accounting for greater than 10% net
credit exposure, as it relates to its natural gas swaps and
options.
As at
September 30, December 31,
($ millions, except for number of customers) 2012 2011
----------------------------------------------------------------------------
Gross credit exposure before credit collateral
(1) 60 136
Credit collateral - -
----------------------------------------------------------------------------
Net credit exposure (2) 60 136
----------------------------------------------------------------------------
Number of counterparties greater than 10% 4 4
Net exposure to counterparties greater than
10% 53 104
----------------------------------------------------------------------------
(1) Gross credit exposure equals mark-to-market value on physically and
financially settled contracts, notes receivable and net receivables
(payables) where netting is contractually allowed. Gross and net credit
exposure amounts reported do not include adjustments for time value or
liquidity.
(2) Net credit exposure is the gross credit exposure collateral minus
credit collateral (cash deposits and letters of credit).
The Corporation is exposed to credit risk associated with the
amount and timing of fair value compensation that Fortis is
entitled to receive from the GOB as a result of the expropriation
of the Corporation's investment in Belize Electricity by the GOB on
June 20, 2011. As at September 30, 2012, the Corporation had a
long-term other asset of $103 million (December 31, 2011 - $106
million; September 30, 2011 - $103 million), including foreign
exchange impacts, recognized on the consolidated balance sheet
related to its expropriated investment in Belize Electricity (Notes
16 and 19).
Additionally, as at September 30, 2012, Belize Electricity owed
Belize Electric Company Limited ("BECOL") approximately US$10
million for energy purchases of which US$6 million was overdue. In
accordance with long-standing agreements, the GOB guarantees the
payment of Belize Electricity's obligations to BECOL.
Liquidity Risk
The Corporation's consolidated financial position could be
adversely affected if it, or one of its subsidiaries, fails to
arrange sufficient and cost-effective financing to fund, among
other things, capital expenditures and the repayment of maturing
debt. The ability to arrange sufficient and cost-effective
financing is subject to numerous factors, including the
consolidated results of operations and financial position of the
Corporation and its subsidiaries, conditions in capital and bank
credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger
regulated utilities have secured committed credit facilities to
support short-term financing of capital expenditures and seasonal
working capital requirements.
The Corporation's committed credit facility is available for
interim financing of acquisitions and for general corporate
purposes. Depending on the timing of cash payments from the
subsidiaries, borrowings under the Corporation's committed credit
facility may be required from time to time to support the servicing
of debt and payment of dividends. As at September 30, 2012, average
annual consolidated long-term debt maturities and repayments over
the next five years are expected to be approximately $295 million.
The combination of available credit facilities and relatively low
annual debt maturities and repayments provide the Corporation and
its subsidiaries with flexibility in the timing of access to
capital markets.
As at September 30, 2012, the Corporation and its subsidiaries
had consolidated credit facilities of approximately $2.5 billion,
of which $2.0 billion was unused. The credit facilities are
syndicated mostly with the seven largest Canadian banks, with no
one bank holding more than 20% of these facilities. Approximately
$2.3 billion of the total credit facilities are committed credit
facilities with maturities ranging from 2013 to 2017.
The following table outlines the credit facilities of the
Corporation and its subsidiaries.
As at
September December
Regulated Fortis Corporate 30, 31,
($ millions) Utilities Properties and Other 2012 2011
----------------------------------------------------------------------------
Total credit
facilities 1,401 13 1,045 2,459 2,248
Credit facilities
utilized:
Short-term
borrowings (1) (97) - - (97) (159)
Long-term debt (2) (63) - (236) (299) (74)
Letters of credit
outstanding (67) - (1) (68) (66)
----------------------------------------------------------------------------
Credit facilities
unused 1,174 13 808 1,995 1,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The weighted average interest rate on short-term borrowings was
approximately 2.2% as at September 30, 2012 (December 31, 2011 - 1.9%).
(2) As at September 30, 2012, credit facility borrowings classified as long
term included $20 million (December 31, 2011 - $16 million) that was
included in current installments of long-term debt on the consolidated
balance sheet. The weighted average interest rate on credit facility
borrowings classified as long-term debt was approximately 2.2% as at
September 30, 2012 (December 31, 2011 - 2.2%).
As at September 30, 2012 and December 31, 2011, certain
borrowings under the Corporation's and subsidiaries' credit
facilities were classified as long-term debt. These borrowings are
under long-term committed credit facilities and management's
intention is to refinance these borrowings with long-term permanent
financing during future periods.
In March 2012 Newfoundland Power renegotiated and amended its
$100 million unsecured committed revolving credit facility,
obtaining an extension to the maturity of the facility from August
2015 to August 2017. The amended credit facility agreement reflects
a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility
agreement.
In April 2012 FortisBC Electric renegotiated and amended its
credit facility agreement resulting in an extension to the maturity
of the Company's $150 million unsecured committed revolving credit
facility with $100 million now maturing in May 2015 and $50 million
now maturing in May 2013.
In May 2012 FHI extended its $30 million operating credit
facility to mature in May 2013 from May 2012. The new agreement
contains substantially similar terms and conditions as the previous
credit facility agreement.
In May 2012 Fortis increased the amount available for borrowing
under its unsecured committed revolving corporate credit facility
from $800 million to $1 billion, as permitted under the credit
facility agreement.
In May 2012 Caribbean Utilities renegotiated and increased the
amount available for borrowing under its unsecured credit
facilities to US$47 million from US$33 million.
In June 2012 FortisOntario entered into a new short-term credit
facility agreement for $30 million, replacing two short-term credit
facilities totaling $20 million. The new credit facility agreement
reflects a decrease in pricing and improved terms and conditions.
In July 2012 the former credit facilities were terminated.
In July 2012 FEI entered into a one-year extension of its $500
million unsecured committed revolving credit facility, extending
the maturity date from August 2013 to August 2014. The amended
credit facility agreement reflects an increase in pricing but,
otherwise, contains substantially similar terms and conditions as
the previous credit facility agreement.
In July 2012 FortisAlberta renegotiated and amended its $250
million unsecured committed revolving credit facility, obtaining an
extension to the maturity of the facility from September 2015 to
August 2016. The amended credit facility agreement reflects a
decrease in pricing but, otherwise, contains substantially similar
terms and conditions as the previous credit facility agreement.
The Corporation and its currently rated utilities target
investment-grade credit ratings to maintain capital market access
at reasonable interest rates. As at September 30, 2012, the
Corporation's credit ratings were as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt
credit rating)
DBRS A (low) (unsecured debt credit rating)
In May 2012 and July 2012, S&P and DBRS, respectively,
affirmed the Corporation's debt credit ratings. Due to the
Corporation's financing plans for the pending acquisition of CH
Energy Group and the expected completion of the Waneta Expansion
hydroelectric generating facility on time and on budget, S&P
and DBRS also removed the ratings from credit watch with negative
implications and under review with developing implications,
respectively, where the ratings had been placed in February
2012.
The above-noted credit ratings reflect the Corporation's low
business-risk profile and diversity of its operations, the
stand-alone nature and financial separation of each of the
regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the
Corporation's reasonable credit metrics and its demonstrated
ability and continued focus on acquiring and integrating stable
regulated utility businesses financed on a conservative basis.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, foreign
subsidiaries are exposed to fluctuations in the US
dollar-to-Canadian dollar exchange rate. The Corporation has
effectively decreased the above-noted exposure through the use of
US dollar borrowings at the corporate level. The foreign exchange
gain or loss on the translation of US dollar-denominated interest
expense partially offsets the foreign exchange loss or gain on the
translation of the Corporation's foreign subsidiaries' earnings,
which are denominated in US dollars. The reporting currency of
Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and
BECOL is the US dollar. Belize Electricity's financial results were
denominated in Belizean dollars, which are pegged to the US
dollar.
As at September 30, 2012, the Corporation's corporately issued
US$557 million (December 31, 2011 - US$550 million) long-term debt
had been designated as an effective hedge of the Corporation's
foreign net investments. As at September 30, 2012, the Corporation
had approximately US$19 million (December 31, 2011 - US$6 million)
in foreign net investments remaining to be hedged. Foreign currency
exchange rate fluctuations associated with the translation of the
Corporation's corporately issued US dollar borrowings designated as
effective hedges are recorded in other comprehensive income and
serve to help offset unrealized foreign currency exchange gains and
losses on the net investments in foreign subsidiaries, which gains
and losses are also recorded in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with
its expropriated investment in Belize Electricity does not qualify
for hedge accounting as Belize Electricity is no longer a foreign
subsidiary of Fortis. As a result, during 2011, a portion of
corporately issued debt that previously hedged the former
investment in Belize Electricity was no longer an effective hedge.
Effective from June 20, 2011, foreign exchange gains and losses on
the translation of the long-term other asset associated with Belize
Electricity and the corporately issued US dollar-denominated debt
that previously qualified as a hedge of the investment were
recognized in earnings. The Corporation has recognized in earnings
foreign exchange losses of approximately $3 million and $2.5
million during the three and nine months ended September 30, 2012,
respectively. During the third quarter of 2011, a foreign exchange
gain of $7 million associated with the translation of the
above-noted US dollar-denominated long-term other asset was
partially offset by a $5.5 million ($4.5 million after tax) foreign
exchange loss associated with the translation of previously hedged
US dollar-denominated long-term debt, resulting in a net foreign
exchange gain of approximately $2.5 million after tax.
FEI's US dollar payments under a contract for the implementation
of a customer care information system were exposed to fluctuations
in the US dollar-to-Canadian dollar exchange rate. FEI had entered
into a foreign exchange forward contract to hedge this exposure.
FEI had regulatory approval to defer any increase or decrease in
the fair value of the foreign exchange forward contract for
recovery from, or refund to, customers in future rates. FEI's
foreign exchange forward contract expired in April 2012.
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to
interest rate risk associated with short-term borrowings and
floating-rate debt. The Corporation and the subsidiaries may enter
into interest rate swap agreements to help reduce this risk.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price
risk associated with changes in the market price of natural gas and
Caribbean Utilities is exposed to commodity price risk associated
with changes in the market price for fuel (Note 16). The risks have
been reduced by entering into natural gas derivatives and fuel
option contracts that effectively fix the price of natural gas
purchases and fuel purchases, respectively. The natural gas
derivatives and fuel option contracts are recorded on the
consolidated balance sheet at fair value and any change in the fair
value is deferred as a regulatory asset or liability, subject to
regulatory approval, for recovery from, or refund to, customers in
future rates.
The price risk-management strategy of the FortisBC Energy
companies aims to improve the likelihood that natural gas prices
remain competitive, to mitigate gas price volatility on customer
rates and to reduce the risk of regional price discrepancies. As
directed by the regulator in 2011, the FortisBC Energy companies
have suspended their commodity hedging activities with the
exception of certain limited swaps as permitted by the regulator.
The existing hedging contracts will continue in effect through to
their maturity and the FortisBC Energy companies' ability to fully
recover the commodity cost of gas in customer rates remains
unchanged. Any differences between the cost of natural gas
purchased and the price of natural gas included in customer rates
are recorded as regulatory deferrals and are recovered from, or
refunded to, customers in future rates, subject to regulatory
approval.
18. COMMITMENTS
There were no material changes in the nature and amount of the
Corporation's commitments from the commitments disclosed in the
Corporation's 2011 US GAAP annual audited consolidated financial
statements, except as described as follows.
a. Pending Acquisitions
In February 2012 Fortis entered into an agreement to acquire CH
Energy Group for US$1.5 billion, including the assumption of
approximately US$500 million in debt on closing. The transaction
received CH Energy Group shareholder approval in June 2012 and
regulatory approval from the Federal Energy Regulatory Commission
and the Committee on Foreign Investment in the United States in
July 2012. In addition, the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in
October 2012, satisfying another condition necessary for
consummation of the transaction. The transaction remains subject to
approval by the NYSPSC and satisfaction of customary closing
conditions. The application for approval of the transaction by the
NYSPSC was jointly filed by Fortis and CH Energy Group in April
2012 (Note 1). The acquisition is expected to close by the end of
the first quarter of 2013 and be immediately accretive to earnings
per common share, excluding acquisition-related expenses.
The agreement and plan of merger may be terminated by the
Corporation or CH Energy Group at any time prior to closing in
certain circumstances, including if the acquisition has not closed
by February 20, 2013, provided, however, that if the only
unsatisfied conditions to closing are the obtaining of the
regulatory approvals as defined in the agreement and plan of
merger, then such date shall be extended to August 20, 2013.
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets, which currently serve approximately
15,000 customers, for approximately $55 million. FortisBC Electric
provides the City of Kelowna with electricity under a wholesale
tariff and has operated and maintained the City of Kelowna's
electrical utility assets since 2000. Closing of the transaction is
subject to certain conditions and receipt of certain approvals,
including regulatory approval. The parties are working towards
closing the transaction by the end of the first quarter of
2013.
b. Subscription Receipts Offering
In June 2012, to finance a portion of the pending acquisition of
CH Energy Group, Fortis sold 18,500,000 Subscription Receipts at
$32.50 each, realizing gross proceeds of approximately $601
million. Each Subscription Receipt will entitle the holder thereof
to receive, on satisfaction of Release Conditions and without
payment of additional consideration, one common share of Fortis and
a cash payment equal to the dividends declared on Fortis common
shares to holders of record during the period from June 27, 2012 to
the date of issuance of the common shares in respect of the
Subscription Receipts. If the Release Conditions are not satisfied
by June 30, 2013, or if the agreement and plan of merger relating
to the acquisition is terminated prior to such time, holders of
Subscription Receipts shall be entitled to receive from the escrow
agent an amount equal to the full subscription price thereof plus
their pro rata share of the interest earned on such amount (Note
4).
c. Other
In January 2012 two First Nations bands each invested
approximately $6 million in equity in the Mount Hayes liquefied
natural gas storage facility, representing a 15% equity interest in
the Mount Hayes Limited Partnership, with FEVI holding the
controlling 85% ownership interest (Note 5). The non-controlling
interests hold put options, which, if exercised, would require FEVI
to repurchase the 15% ownership interest for cash, in accordance
with the terms of the partnership agreement.
In April 2012 the December 31, 2011 actuarial valuation of the
defined benefit pension plan at Newfoundland Power was completed.
As a result Newfoundland Power is required to fund a solvency
deficiency of approximately $53 million, including interest, over
five years beginning in 2012. The Company fulfilled its 2012 annual
solvency deficit funding requirement during the second quarter of
2012. The increase in funding contributions is expected to be
recovered from customers in future rates.
In September 2012 Caribbean Utilities entered into primary and
secondary fuel supply contracts with two different suppliers and is
committed to purchasing approximately 60% and 40% of the Company's
diesel fuel requirements under each of the contracts, respectively,
for the operation of Caribbean Utilities' diesel-powered generating
plant. The approximate combined quantities under the contracts,
expressed in millions of imperial gallons, on an annual basis by
fiscal year are: 2012 - 10.8, 2013 - 32.4 and 2014 - 18.9. The
contracts expire in July 2014 with the option to renew for two
additional 18-month terms. The renewal options can be exercised
only within six months of the expiry dates of the existing
contracts.
19. EXPROPRIATED ASSETS
Belize Electricity
On June 20, 2011, the GOB enacted legislation leading to the
expropriation of the Corporation's investment in Belize
Electricity. Consequent to the deprivation of control over the
operations of the utility, the Corporation discontinued the
consolidation method of accounting for Belize Electricity,
effective June 20, 2011, and classified the book value, including
foreign exchange impacts, of the expropriated investment in the
utility as a long-term other asset on the consolidated balance
sheet.
In October 2011 Fortis commenced an action in the Belize Supreme
Court with respect to the challenge of the legality of the
expropriation of the Corporation's investment in Belize
Electricity. Fortis commissioned an independent valuation of its
expropriated investment in Belize Electricity and submitted its
claim for compensation to the GOB in November 2011. The book value
of the long-term other asset is below fair value as at the date of
expropriation as determined under the Corporation's valuation. The
GOB also commissioned a valuation of Belize Electricity and
communicated the results of such valuation in its response to the
Corporation's claim for compensation. The fair value of Belize
Electricity determined under the GOB's valuation is significantly
lower than both the fair value determined under the Corporation's
valuation and the book value of the long-term other asset.
In July 2012 the Belize Supreme Court dismissed the
Corporation's claim of October 2011. Also in July 2012, Fortis
filed its appeal of the above-noted trial judgment in the Belize
Court of Appeal. The appeal was heard in October 2012 and a
decision on the appeal has been suspended pending the outcome of
another related appeal in the Caribbean Court of Justice ("CCJ"). A
possible outcome of the appeal could be the return to Fortis of the
majority ownership interest in Belize Electricity. Alternatively,
in the event that the Belize Court of Appeal decision confirms the
trial judgment, Fortis could pursue an appeal of the case to the
CCJ, the highest court of appeal available for judical matters in
Belize.
Fortis believes it has a strong, well-positioned case before the
Belize Courts and will continue to vigorously litigate the legality
of the expropriation. There exists, however, a reasonable
possibility that the outcome of the above-noted litigation may be
unfavourable to the Corporation and the amount of compensation to
be paid to Fortis could be lower than the book value of its
expropriated investment in Belize Electricity, which was $103
million, including foreign exchange impacts, as at September 30,
2012 (December 31, 2011 - $106 million; September 30, 2011 - $103
million) and recorded in long-term other assets on the consolidated
balance sheet. Based on presently available information, the
outcome of the above is not determinable at this time. As such, the
long-term other asset is not deemed impaired. Fortis will continue
to assess for impairment each reporting period based on the
outcomes of court proceedings and/or compensation settlement
negotiations, if any. As well as continuing its legal actions,
Fortis is also pursuing alternative options for obtaining fair
compensation.
Exploits River Hydro Partnership
The Exploits River Hydro Partnership ("Exploits Partnership") is
owned 51% by Fortis Properties and 49% by AbitibiBowater Inc.
("Abitibi"). The Exploits Partnership operated two non-regulated
hydroelectric generating facilities in central Newfoundland with a
combined capacity of approximately 36 MW. In December 2008 the
Government of Newfoundland and Labrador expropriated Abitibi's
hydroelectric assets and water rights in Newfoundland, including
those of the Exploits Partnership. The newsprint mill in Grand
Falls-Windsor closed on February 12, 2009, subsequent to which the
day-to-day operations of the Exploits Partnership's hydroelectric
generating facilities were assumed by Nalcor Energy as an agent for
the Government of Newfoundland and Labrador with respect to
expropriation matters. The Government of Newfoundland and Labrador
has publicly stated that it is not its intention to adversely
affect the business interests of lenders or independent partners of
Abitibi in the province. The loss of control over cash flows and
operations required Fortis to cease consolidation of the Exploits
Partnership, effective February 12, 2009. Discussions between
Fortis Properties and Nalcor Energy with respect to expropriation
matters are ongoing.
20. CONTINGENT LIABILITIES
The Corporation and its subsidiaries are subject to various
legal proceedings and claims associated with the ordinary course of
business operations. Management believes that the amount of
liability, if any, from these actions would not have a material
effect on the Corporation's consolidated financial position or
results of operations.
The following describes the nature of the Corporation's
contingent liabilities.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed
settlement agreement with counsel to plaintiff shareholders
pertaining to several complaints, which named Fortis and other
defendants, which were filed in, or transferred to, the Supreme
Court of the State of New York, County of New York, relating to the
proposed acquisition of CH Energy Group by Fortis. The complaints
generally alleged that the directors of CH Energy Group breached
their fiduciary duties in connection with the proposed acquisition
and that CH Energy Group, Fortis, FortisUS Inc. and Cascade
Acquisition Sub Inc. aided and abetted that breach. The settlement
agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received
Notices of Assessment from Canada Revenue Agency for additional
taxes related to the taxation years 1999 through 2003. The exposure
has been fully provided for in the consolidated financial
statements. FHI is appealing these assessments.
In 2009 FHI was named, along with other defendants, in an action
related to damages to property and chattels, including
contamination to sewer lines and costs associated with remediation,
related to the rupture in July 2007 of an oil pipeline owned and
operated by Kinder Morgan, Inc. FHI filed a statement of defence.
During the second quarter of 2010, FHI was added as a third party
in all of the related actions. FHI was advised that all matters
have now been settled and the action has been dismissed by
consent.
FortisBC Electric
The Government of British Columbia has alleged breaches of the
Forest Practices Code and negligence relating to a forest fire near
Vaseux Lake and has filed and served a writ and statement of claim
against FortisBC Electric dated August 2, 2005. The Government of
British Columbia has now disclosed that its claim includes
approximately $13.5 million in damages but that it has not fully
quantified its damages. In addition, private landowners have filed
separate writs and statements of claim dated August 19, 2005 and
August 22, 2005 for undisclosed amounts in relation to the same
matter. FortisBC Electric and its insurers are defending the
claims. A date for mediation of this matter has been set for
December 2012. The outcome cannot be reasonably determined and
estimated at this time and, accordingly, no amount has been accrued
in the consolidated financial statements.
The Government of British Columbia filed a claim in the British
Columbia Supreme Court in June 2012 claiming on its behalf, and on
behalf of approximately 17 homeowners, damages suffered as a result
of a landslide caused by a dam failure in Oliver, British Columbia
in 2010. The Government of British Columbia alleges in its claim
that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government
of British Columbia estimates its damages and the damages of the
homeowners, on whose behalf it is claiming, to be approximately $12
million. FortisBC Electric has not been served, however, has
retained counsel and has contacted its insurers. The outcome cannot
be reasonably determined and estimated at this time and,
accordingly, no amount has been accrued in the consolidated
financial statements.
21. SUBSEQUENT EVENT
In October 2012 FortisAlberta issued 40-year $125 million 3.98%
unsecured debentures, the proceeds from which are being used to
repay borrowings under the Company's credit facility, fund future
capital expenditures, and for general corporate purposes.
22. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply
with current period presentation. The most significant change
related to a decrease in current and long-term debt of $4 million
and $120 million, respectively, and a corresponding increase in
current and long-term capital lease and finance obligations
associated with a change in the presentation of finance
obligations.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility
in Canada, with total assets of more than $14 billion and fiscal
2011 revenue totalling approximately $3.7 billion. The Corporation
serves more than 2,000,000 gas and electricity customers. Its
regulated holdings include electric distribution utilities in five
Canadian provinces and two Caribbean countries and a natural gas
utility in British Columbia. Fortis owns and operates non-regulated
generation assets across Canada and in Belize and Upstate New York.
It also owns hotels and commercial office and retail space in
Canada.
The Common Shares, First Preference Shares, Series C; First
Preference Shares, Series E; First Preference Shares, Series F;
First Preference Shares, Series G; First Preference Shares, Series
H; and Subscription Receipts of Fortis are traded on the Toronto
Stock Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F,
FTS.PR.G, FTS.PR.H and FTS.R, respectively.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2011 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.
Contacts: Barry V. Perry Vice President Finance and Chief
Financial Officer Fortis Inc. 709.737.2822
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