Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) recorded second quarter
net earnings applicable to common shares of $53 million, or $0.31 per common
share, compared to earnings of $29 million, or $0.19 per common share, for the
second quarter of 2008. Year-to-date earnings applicable to common shares were
$145 million, or $0.85 per common share, compared to earnings of $120 million,
or $0.77 per common share, for the same period last year.
"Fortis delivered positive results for the quarter, led by our Canadian
Regulated Utilities, despite challenging economic conditions," explains Stan
Marshall, President and Chief Executive Officer, Fortis Inc.
Results for the second quarter last year included one-time charges of
approximately $15 million pertaining to Belize Electricity and FortisOntario.
Excluding these one-time charges, earnings increased $9 million quarter over
quarter driven by contributions from FortisAlberta and the Terasen Gas
companies, partially offset by lower earnings from non-regulated hydroelectric
generation.
The Terasen Gas companies contributed earnings of $14 million for the second
quarter of 2009, up $2 million from the same quarter last year. The increase was
mainly due to lower corporate income taxes and finance charges.
Canadian Regulated Electric Utilities contributed $39 million to earnings for
the second quarter, up $13 million from the same quarter last year. Excluding
the $2 million one-time charge at FortisOntario associated with the repayment of
an interconnection agreement-related refund during the second quarter of 2008,
earnings from Canadian Regulated Electric Utilities were $11 million higher
quarter over quarter. The increase was driven by lower corporate income taxes
and growth in electrical infrastructure investment at FortisAlberta.
In June 2009, FortisOntario entered into an agreement to acquire Great Lakes
Power Distribution Inc., an electric distribution utility serving approximately
12,000 customers in the district of Algoma in northern Ontario, for
approximately $68 million, subject to adjustment and customary regulatory
approvals.
During the second quarter of 2009, Terasen Gas, Terasen Gas (Vancouver Island)
and FortisAlberta each filed applications with their respective regulators to
set 2010 and 2011 customer rates and Newfoundland Power filed an application
with its regulator to set 2010 customer rates. All of these utilities have
requested or are currently engaged in a cost of capital review, the outcome of
which could result in a change in their allowed rates of return on common
shareholder's equity.
Caribbean Regulated Electric Utilities contributed $7 million to earnings
compared to a $5 million loss incurred in the second quarter of 2008. Excluding
the $13 million loss in 2008 associated with the June 2008 regulatory rate
decision at Belize Electricity, earnings at Caribbean Regulated Electric
Utilities were $1 million lower quarter over quarter. Results for the quarter
reflected a lower allowed rate of return on rate base assets at Belize
Electricity, effective July 1, 2008.
Non-Regulated Fortis Generation contributed $3 million to earnings compared to
$7 million for the second quarter of 2008. As expected, results for the quarter
were unfavourably impacted by the loss of earnings subsequent to the expiration,
on April 30, 2009, of the power-for-water exchange agreement related to the
Rankine hydroelectric generating facility in Ontario. Earnings also decreased
due to lower average wholesale market energy prices in Upper New York State and
Ontario quarter over quarter.
Fortis Properties contributed earnings of $8 million, up $1 million from the
second quarter of 2008, mainly due to increased contribution from the Real
Estate Division combined with lower corporate operating expenses, partially
offset by lower contribution from the Hospitality Division, mainly caused by
lower hotel occupancies. In April 2009, Fortis Properties acquired the 214-room
Holiday Inn Select in Windsor, Ontario for approximately $7 million. Fortis
Properties now owns 21 hotels with more than 4,000 rooms in eight Canadian
provinces.
Corporate and other expenses were $18 million, comparable to the same quarter in
2008. Lower finance charges primarily due to decreased borrowing levels quarter
over quarter, were largely offset by higher preference share dividends related
to the issuance of First Preference Shares, Series G during the second quarter
of 2008. In December 2008, Fortis completed a $300 million common share issue,
the net proceeds of which were primarily used to repay short-term debt incurred
to repay maturing long-term debt.
Cash flow from operating activities was $275 million in the second quarter, up
from $232 million in the same quarter last year. Cash flow from operating
activities was $504 million year to date, up from $425 million in the same
period last year. The increases were driven by higher earnings and favourable
working capital changes at FortisAlberta and the Terasen Gas companies.
"Fortis and its subsidiaries successfully raised long-term debt at attractive
rates during a period of global economic uncertainty and capital market
volatility, demonstrating the strength of our core utility business," says
Marshall.
Fortis and its utilities have raised over $600 million of long-term debt year to
date, including 30-year $200 million 6.51% unsecured debentures at Fortis,
30-year $105 million 6.10% unsecured debentures at FortisBC, 15-year US$40
million 7.50% unsecured notes at Caribbean Utilities, 30-year $65 million 6.606%
first mortgage bonds at Newfoundland Power, 30-year $100 million 7.06% unsecured
debentures at FortisAlberta, and 30-year $100 million 6.55% unsecured debentures
at Terasen Gas.
"Our subsidiaries are focused on completing their capital projects for 2009,
estimated to total more than $1 billion this year," says Marshall. "Much of this
investment is occurring at our utilities in western Canada and the Caribbean.
Some of the larger projects in progress include construction of the liquefied
natural gas storage facility at Terasen Gas (Vancouver Island), the installation
of automated meters at FortisAlberta, the Okanagan Transmission Reinforcement
Project at FortisBC and the 19-megawatt hydroelectric generating facility in
Belize," he explains.
"Over the five years 2009 through 2013, our consolidated capital program is
expected to total approximately $5 billion, substantially all of which will be
funded at the subsidiary level," says Marshall. "This capital investment will
add value for customers and shareholders and fortify the position of Fortis as a
leading owner of energy infrastructure in Canada," concludes Marshall.
Interim Management Discussion and Analysis
For the three and six months ended June 30, 2009
Dated August 5, 2009
The following analysis should be read in conjunction with the Fortis Inc.
("Fortis" or the "Corporation") interim unaudited consolidated financial
statements and notes thereto for the three and six months ended June 30, 2009
and the Management Discussion and Analysis ("MD&A") and audited consolidated
financial statements for the year ended December 31, 2008 included in the
Corporation's 2008 Annual Report. This material has been prepared in accordance
with National Instrument 51-102 - Continuous Disclosure Obligations relating to
MD&As. Financial information in this release has been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP") and is
presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of
applicable securities laws in Canada ("forward-looking information"). The
purpose of the forward-looking information is to provide management's
expectations regarding the Corporation's future growth, results of operations,
performance, business prospects and opportunities, and it may not be appropriate
for other purposes. All forward-looking information is given pursuant to the
"safe harbour" provisions of applicable Canadian securities legislation. The
words "anticipates", "believes", "budgets", "could", "estimates", "expects",
"forecasts", "intends", "may", "might", "plans", "projects", "schedule",
"should", "will", "would" and similar expressions are often intended to identify
forward-looking information, although not all forward-looking information
contains these identifying words. The forward-looking information reflects
management's current beliefs and is based on information currently available to
the Corporation's management. The forward-looking information in the MD&A
includes, but is not limited to, statements regarding: the expected timing of
regulatory decisions; consolidated forecasted gross capital expenditures for
2009 and in total over the five year period from 2009 to 2013; the nature,
timing and amount of certain capital projects; the expected impacts on Fortis of
the downturn in the global economy; the electricity sales growth rate expected
at the Corporation's regulated utilities in the Caribbean in 2009; the
expectation of no significant decrease in annual consolidated operating cash
flows in 2009; the expectation that the subsidiaries will be able to source the
cash required to fund their 2009 capital expenditure programs; the expectation
that the Corporation and its subsidiaries will continue to have reasonable
access to long-term capital in the near to medium terms; expected long-term debt
maturities and repayments on average annually over the next five years;
no material increase in interest expense and/or fees associated with renewed
and extended credit facilities is expected in 2009; no material adverse credit
rating actions are expected in the near term; the expectation that
counterparties to the Terasen Gas companies' gas derivative contracts will
continue to meet their obligations; and the expectation of no material increase
in defined benefit pension expense in 2009. The forecasts and projections that
make up the forward-looking information are based on assumptions which include,
but are not limited to: the receipt of applicable regulatory approvals and
requested rate orders; no significant operational disruptions or environmental
liability due to a catastrophic event or environmental upset caused by severe
weather, other acts of nature or other major event; the continued ability to
maintain the gas and electricity systems to ensure their continued performance;
no significant decline in capital spending in 2009; no severe and prolonged
downturn in economic conditions; sufficient liquidity and capital resources; the
continuation of regulator-approved mechanisms to flow through the commodity cost
of natural gas and energy supply costs in customer rates; the continued ability
to hedge exposures to fluctuations in interest rates, foreign exchange rates and
natural gas commodity prices; no significant variability in interest rates; no
significant counterparty defaults; the continued competitiveness of natural gas
pricing when compared with electricity and other alternative sources of energy;
the continued availability of natural gas supply; the continued ability to fund
defined benefit pension plans; the absence of significant changes in government
energy plans and environmental laws that may materially affect the operations
and cash flows of the Corporation and its subsidiaries; maintenance of adequate
insurance coverage; the ability to obtain and maintain licences and permits;
retention of existing service areas; no material decrease in market energy
sales prices; favourable relations with First Nations; favourable labour
relations; and sufficient human resources to deliver service and execute the
capital program. The forward-looking information is subject to risks,
uncertainties and other factors that could cause actual results to differ
materially from historical results or results anticipated by the forward-looking
information. Factors which could cause results or events to differ from current
expectations include, but are not limited to: regulatory risk; operating and
maintenance risks; economic conditions; capital resources and liquidity risk;
weather and seasonality; an ultimate resolution of the expropriation of the
assets of the Exploits River Hydro Partnership that differs from what is
currently expected by management; commodity price risk; derivative financial
instruments and hedging; interest rate risk; counterparty risk; competitiveness
of natural gas; natural gas supply; defined benefit pension plan performance and
funding requirements; risks related to the development of the Terasen Gas
(Vancouver Island) Inc. franchise; the Government of British Columbia's Energy
Plan; environmental risks; insurance coverage risk; an unexpected outcome of any
legal proceedings currently against the Corporation; loss of licences and
permits; loss of service area; market energy sales prices; changes in current
assumptions and expectations associated with the transition to International
Financial Reporting Standards; changes in tax legislation; relations with First
Nations; labour relations; and human resources. For additional information with
respect to the Corporation's risk factors, reference should be made to the
Corporation's continuous disclosure materials filed from time to time with
Canadian securities regulatory authorities and to the heading "Business Risk
Management" in the MD&A for the three and six months ended June 30, 2009 and for
the year ended December 31, 2008.
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.
COMPANY OVERVIEW AND FINANCIAL HIGHLIGHTS
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 three Caribbean
countries and a natural gas utility in British Columbia. Fortis owns and
operates non-regulated generation assets across Canada and in Belize and Upper
New York State and hotels and commercial real estate in Canada. Year-to-date
June 30, 2009, the Corporation's electric utilities met a combined peak
electricity demand of approximately 5,679 megawatts ("MW") and its gas utility
met a peak day demand of 1,234 terajoules ("TJ"). For additional information on
the Corporation's business segments, refer to Note 1 to the Corporation's
interim unaudited consolidated financial statements for the three and six months
ended June 30, 2009.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably to customers at reasonable rates, and conduct business in an
environmentally responsible manner. The Corporation's core utility business is
highly regulated. It is segmented by franchise area and, depending on regulatory
requirements, by the nature of the assets.
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. Key financial highlights, including
earnings by reportable segment for the second quarter and year-to-date periods
ended June 30, 2009 and June 30, 2008, are provided in the following table.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions, except
earnings per
common share and
common shares
outstanding) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Revenue 754 848 (94) 1,955 1,994 (39)
-------------------------------------------------------------------------
Cash flow from
operating activities 275 232 43 504 425 79
-------------------------------------------------------------------------
Net earnings applicable
to common shares 53 29 24 145 120 25
-------------------------------------------------------------------------
Basic earnings per
common share ($) 0.31 0.19 0.12 0.85 0.77 0.08
-------------------------------------------------------------------------
Diluted earnings per
common share ($) 0.31 0.18 0.13 0.83 0.75 0.08
-------------------------------------------------------------------------
Weighted average number
of common shares
outstanding (millions) 170.0 157.0 13.0 169.7 156.8 12.9
-------------------------------------------------------------------------
Segmented Net Earnings
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Regulated Gas Utilities
- Canadian
-------------------------------------------------------------------------
Terasen Gas
Companies (1) 14 12 2 72 70 2
-------------------------------------------------------------------------
Regulated
Electric Utilities
- Canadian
-------------------------------------------------------------------------
FortisAlberta 17 7 10 29 18 11
-------------------------------------------------------------------------
FortisBC (2) 7 7 - 21 19 2
-------------------------------------------------------------------------
Newfoundland Power 11 10 1 17 16 1
-------------------------------------------------------------------------
Other Canadian (3) 4 2 2 9 6 3
-------------------------------------------------------------------------
39 26 13 76 59 17
-------------------------------------------------------------------------
Regulated Electric
Utilities
- Caribbean (4) 7 (5) 12 13 2 11
-------------------------------------------------------------------------
Non-Regulated
- Fortis
Generation (5) 3 7 (4) 9 13 (4)
-------------------------------------------------------------------------
Non-Regulated
- Fortis
Properties (6) 8 7 1 10 10 -
-------------------------------------------------------------------------
Corporate and
Other (7) (18) (18) - (35) (34) (1)
-------------------------------------------------------------------------
Net Earnings
Applicable to
Common Shares 53 29 24 145 120 25
-------------------------------------------------------------------------
(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island)
Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI")
(2) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant
and Arrow Lakes hydroelectric generating plants and the distribution
system owned by the City of Kelowna. Excludes the non-regulated
generation operations of FortisBC Inc.'s wholly owned partnership,
Walden Power Partnership.
(3) Includes Maritime Electric and FortisOntario. FortisOntario includes
Canadian Niagara Power and Cornwall Electric.
(4) Includes Belize Electricity, in which Fortis holds an approximate 70
per cent controlling interest; Caribbean Utilities on Grand Cayman,
Cayman Islands, in which Fortis holds an approximate 59.5 per cent
controlling interest, including an additional 2.7 per cent interest
acquired in July 2009; and wholly owned Fortis Turks and Caicos.
Previously, Caribbean Utilities had an April 30th fiscal year end
whereby, up to and including the third quarter of 2008, its financial
statements were consolidated in the financial statements of Fortis on a
two-month lag basis. In 2008, Caribbean Utilities changed its fiscal
year end to December 31st. The change in Caribbean Utilities' fiscal
year end eliminates the previous two-month lag in consolidating its
financial results.
(5) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State, with a combined generating capacity of 120 MW, mainly
hydroelectric. Prior to May 1, 2009, the Corporation's financial
results reflected earnings' contribution associated with the
Corporation's 75-MW water-right entitlement on the Niagara River in
Ontario under the Niagara Exchange Agreement related to the Rankine
hydroelectric generating facility. The Niagara Exchange Agreement
expired on April 30, 2009, in accordance with its terms. Additionally,
prior to February 13, 2009, the financial results of the hydroelectric
generation operations in central Newfoundland were consolidated in the
financial statements of Fortis. As of February 13, 2009, the financial
results of the generation operations in central Newfoundland have been
recorded in the financial statements of Fortis on an equity basis, due
to the Corporation no longer having control over the generation
operations as a result of the expropriation of the related assets by
the Government of Newfoundland and Labrador. The change in the method
of accounting did not have a material impact on segmented or
consolidated earnings. For a further discussion of this matter, refer
to the "Critical Accounting Estimates - Contingencies" section of this
MD&A.
(6) Fortis Properties owns 21 hotels with more than 4,000 rooms in eight
Canadian provinces and approximately 2.8 million square feet of
commercial real estate primarily in Atlantic Canada.
(7) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen Inc. ("Terasen") corporate-related activities and the financial
results of Terasen's 30 per cent ownership interest in CustomerWorks
Limited Partnership ("CWLP") and of Terasen's non-regulated wholly
owned subsidiary Terasen Energy Services Inc.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
Terasen Gas Companies
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Terasen Gas Companies
Financial Highlights (Unaudited)
Periods Ended June 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
--------------------------------------------------------------------------
Gas Volumes (TJ) 36,451 45,324 (8,873) 114,421 123,508 (9,087)
--------------------------------------------------------------------------
($ millions)
--------------------------------------------------------------------------
Revenue 289 390 (101) 958 1,025 (67)
--------------------------------------------------------------------------
Energy Supply Costs 156 256 (100) 624 693 (69)
--------------------------------------------------------------------------
Operating Expenses 62 62 - 129 123 6
--------------------------------------------------------------------------
Amortization 26 25 1 51 49 2
--------------------------------------------------------------------------
Finance Charges 29 30 (1) 61 63 (2)
--------------------------------------------------------------------------
Corporate Taxes 2 5 (3) 21 27 (6)
--------------------------------------------------------------------------
Earnings 14 12 2 72 70 2
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gas Volumes: Gas volumes at the Terasen Gas companies decreased 8,873 TJ, or
19.6 per cent, quarter over quarter and decreased 9,087 TJ, or 7.4 per cent,
year to date compared to the same period last year. The decreases were driven
by the Company's core residential customers, mainly due to lower average
consumption as a result of warmer-than-normal weather experienced during the
quarter compared to cooler-than-normal weather experienced during the same
quarter last year. Tempering the decrease in gas volumes year to date was the
favourable impact on residential customer consumption during the first quarter
of 2009, due to cooler-than-normal weather experienced during that period. The
decrease in gas volumes attributable to residential customers was 5,071 TJ
quarter over quarter and 3,828 TJ year to date compared to the same period last
year. Also, to a lesser extent, the impact of the general economic slowdown
unfavourably impacted gas volumes to customers under fixed price contracts and
transportation volumes to customers sourcing their own gas supplies.
The Terasen Gas companies earn approximately the same margin regardless of
whether a customer contracts for the purchase of natural gas or for the
transportation of natural gas only.
As a result of the operation of regulatory approved deferral mechanisms, changes
in consumption levels and energy supply costs from those forecasted to set gas
distribution rates do not materially affect earnings.
During the second quarter of 2009, combined net customer losses at Terasen Gas
Inc. ("TGI") and Terasen Gas (Vancouver Island) Inc. ("TGVI") totalled
approximately 1,200, bringing the total customer count at the Terasen Gas
companies to approximately 932,500 as at June 30, 2009. Year-to-date 2009, net
customer additions were approximately 1,100 compared to net customer additions
of approximately 3,300 for the same period in 2008. Continued weakening housing
and construction markets, due to slowing economic growth, and growth in
multi-family housing, where natural gas use is less prevalent compared to
single-family housing, has resulted in slower customer growth during the first
half of 2009 compared to the first half of 2008.
Revenue: Revenue was $101 million lower quarter over quarter and $67 million
lower year to date compared to the same period last year. The decreases were
driven by lower commodity costs charged to customers and lower consumption,
partially offset by higher basic customer delivery rates compared to the same
periods in 2008.
Effective January 1, 2009, basic customer delivery rates at TGI increased
approximately 6 per cent while basic customer delivery rates at TGVI increased
up to 5 per cent based on customer rate class. The basic delivery rates for
2009, however, reflect the impact of a decrease in the allowed rate of return on
common shareholder's equity ("ROE") to 8.47 per cent from 8.62 per cent for TGI
and to 9.17 per cent from 9.32 per cent for TGVI.
Earnings: Earnings were $2 million higher quarter over quarter and $2 million
higher year to date compared to the same period last year. The increases were
mainly due to a lower effective corporate income tax rate, lower finance charges
related to decreased borrowing rates and lower borrowings under credit
facilities, and higher basic customer delivery rates, partially offset by
increased amortization costs associated with continued investment in capital
assets. The increase in earnings year to date compared to the same period last
year was also partially offset by higher operating expenses, driven by increased
labour and employee-benefit costs. The decrease in the effective corporate
income tax rate was primarily due to higher deductions taken for tax purposes
compared to accounting purposes.
In February 2009, TGI issued 30-year $100 million 6.55% unsecured debentures.
For additional information, see the "Liquidity and Capital Resources" section of
this MD&A.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Terasen Gas companies, refer to the
"Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CANADIAN
FortisAlberta
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Alberta
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Energy Deliveries (GWh) 3,765 3,768 (3) 7,917 7,906 11
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 81 75 6 160 148 12
-------------------------------------------------------------------------
Operating Expenses 31 32 (1) 65 65 -
-------------------------------------------------------------------------
Amortization 23 21 2 45 41 4
-------------------------------------------------------------------------
Finance Charges 13 11 2 24 20 4
-------------------------------------------------------------------------
Corporate Tax
(Recovery) Expense (3) 4 (7) (3) 4 (7)
-------------------------------------------------------------------------
Earnings 17 7 10 29 18 11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Deliveries: Energy deliveries at FortisAlberta decreased 3 gigawatt
hours ("GWh"), or 0.1 per cent, quarter over quarter, mainly due to a decrease
in the number of oil and gas customers and lower average consumption by
commercial customers, partially offset by an increase in residential,
commercial, farm and irrigation customers. Energy deliveries increased 11 GWh,
or 0.1 per cent, year to date compared to the same period last year, mainly due
to an increase in residential, commercial, farm and irrigation customers and the
impact of cooler-than-normal weather during the first quarter of 2009, partially
offset by a decrease in the number of oil and gas customers and lower average
consumption by that customer class. The number of customers at FortisAlberta
increased by 3,600 to approximately 464,600 during the first half of 2009.
As a significant portion of the Company's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered do not directly correlate with changes in revenues.
Revenue: Revenue was $6 million higher quarter over quarter and $12 million
higher year to date compared to the same period last year, mainly due to an 8.6
per cent increase in customer distribution rates, effective January 1, 2009, and
the impact of load and customer growth. Customer distribution rates for 2009
reflect the impact of ongoing investment in electrical infrastructure and
collection from customers in 2009 of the increase in the allowed ROE for 2008
that was accrued in 2008. Rates for 2009 reflect an interim allowed ROE of 8.51
per cent compared to an allowed ROE of 8.75 per cent for 2008.
Earnings: Earnings were $10 million higher quarter over quarter and $11 million
higher year to date compared to the same period last year. Lower corporate
income taxes and the impact of the increase in customer distribution rates and
overall load and customer growth was partially offset by: (i) increased
amortization costs associated with continued investment in capital assets; and
(ii) increased finance charges due to higher debt levels in support of the
Company's significant capital expenditure program, partially offset by the
impact of lower interest rates on credit facility borrowings. The decrease in
corporate income taxes was primarily due to a change in tax strategy during the
third quarter of 2008 related to the Company's regulator-approved Alberta
Electric System Operator ("AESO") charges deferral account, combined with a
higher current income tax recovery. Prior to the third quarter of 2008,
FortisAlberta was not deducting for income tax purposes transmission tariff
payments made to the AESO to create tax loss carryforwards and, therefore, was
not recording the associated future income tax recoveries. The result was
future income tax expense being recorded during the first half of 2008. Also,
the collection of the balance of the 2007 AESO charges deferral account that was
not sold to a Canadian chartered bank in 2007 results in a future income tax
recovery in 2009.
In February 2009, FortisAlberta issued 30-year $100 million 7.06% unsecured
debentures. For additional information, see the "Liquidity and Capital
Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisAlberta, refer to the "Regulatory
Highlights" section of this MD&A.
FortisBC
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis BC
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Electricity Sales (GWh) 675 673 2 1,578 1,548 30
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 55 53 2 127 119 8
-------------------------------------------------------------------------
Energy Supply Costs 13 12 1 35 33 2
-------------------------------------------------------------------------
Operating Expenses 17 17 - 34 33 1
-------------------------------------------------------------------------
Amortization 9 8 1 19 17 2
-------------------------------------------------------------------------
Finance Charges 8 7 1 15 14 1
-------------------------------------------------------------------------
Corporate Taxes 1 2 (1) 3 3 -
-------------------------------------------------------------------------
Earnings 7 7 - 21 19 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at FortisBC increased 2 GWh, or 0.3 per
cent, quarter over quarter and increased 30 GWh, or 1.9 per cent, year to date
compared to the same period last year, primarily due to growth in residential
and general service customers, partially offset by a decrease in the number of
industrial customers.
Revenue: Revenue was $2 million higher quarter over quarter and $8 million
higher year to date compared to the same period last year. The increases were
driven by a 4.6 per cent increase in customer electricity rates, effective
January 1, 2009; a 0.8 per cent increase in customer electricity rates,
effective May 1, 2008, as a result of the flow through to customers of increased
power purchase costs from BC Hydro; and electricity sales growth. Electricity
rates for 2009 reflect the impact of ongoing investment in electrical
infrastructure and an allowed ROE of 8.87 per cent compared to 9.02 per cent for
2008.
Earnings: FortisBC's earnings were comparable quarter over quarter. The impact
of the increases in electricity rates and customer growth was offset by: (i)
higher energy supply costs associated with increased electricity sales, a higher
proportion of purchased power versus energy generated from Company-owned
hydroelectric generating plants and the receipt of $0.6 million of insurance
proceeds during the second quarter of last year associated with a turbine
failure in 2006, partially offset by the impact of lower average prices for
purchased power; (ii) increased amortization costs associated with continued
investment in capital assets; and (iii) higher finance charges reflecting
increased debt levels in support of the Company's significant capital
expenditure program and increased credit facility renewal fees, partially offset
by the impact of lower interest rates on credit-facility borrowings.
Earnings increased $2 million year to date compared to the same period last
year. The impact of the increases in electricity rates and customer growth was
partially offset by the same factors for the quarter, as described above,
combined with higher operating expenses. The increase in operating expenses was
mainly due to the timing of maintenance projects during 2009, higher labour
costs, general inflationary cost increases and higher water and wheeling fees.
In June 2009, FortisBC issued 30-year $105 million 6.10% unsecured debentures,
under a short-form base shelf prospectus filed in May 2009 for the issuance of
up to $300 million in debentures from time to time during the 25-month life of
the shelf prospectus. For additional information, see the "Liquidity and
Capital Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisBC, refer to the "Regulatory Highlights"
section of this MD&A.
Newfoundland Power
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Newfoundland Power
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Electricity Sales (GWh) 1,177 1,183 (6) 2,940 2,899 41
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 119 120 (1) 288 284 4
-------------------------------------------------------------------------
Energy Supply Costs 70 70 - 197 192 5
-------------------------------------------------------------------------
Operating Expenses 13 13 - 27 27 -
-------------------------------------------------------------------------
Amortization 11 12 (1) 22 22 -
-------------------------------------------------------------------------
Finance Charges 9 9 - 17 17 -
-------------------------------------------------------------------------
Corporate Taxes 5 6 (1) 8 10 (2)
-------------------------------------------------------------------------
Earnings 11 10 1 17 16 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at Newfoundland Power decreased 6 GWh, or
0.5 per cent, quarter over quarter, due to lower average consumption, partially
offset by the impact of customer growth. Electricity sales increased 41 GWh, or
1.4 per cent, year to date compared to the same period last year primarily due
to the impact of customer growth.
Revenue: Revenue was $1 million lower quarter over quarter due to lower
amortization to revenue of certain regulatory liabilities, in accordance with
prescribed regulatory orders, and lower electricity sales, partially offset by a
gain on the sale of property. Revenue was $4 million higher year to date
compared to the same period last year, driven by electricity sales growth,
partially offset by lower amortization to revenue of certain regulatory
liabilities, as described above for the quarter. The allowed ROE of 8.95 per
cent for 2009 remains unchanged from 2008 and, consequently, there has been no
change in basic customer rates for 2009.
Earnings: Newfoundland Power's earnings were $1 million higher quarter over
quarter mainly due to lower amortization costs, driven by a change in the
quarterly allocation of those costs, the impact of a lower effective corporate
income tax rate and a gain on the sale of property, partially offset by the
impact of decreased electricity sales. For 2009, amortization is being
allocated each quarter based on capitalized assets in service. In 2008,
amortization was allocated each quarter based on sales margin.
Earnings were $1 million higher year to date compared to the same period last
year, mainly due to the impact of increased electricity sales and a lower
effective corporate income tax rate, partially offset by the impact of higher
demand charges from Newfoundland and Labrador Hydro Corporation ("Newfoundland
Hydro"), associated with meeting peak load requirements during the winter
season.
The decrease in the effective corporate income tax rate was primarily due to
higher deductions taken for tax purposes compared to accounting purposes in 2009
compared to 2008.
In May 2009, Newfoundland Power privately placed 30-year $65 million 6.606%
first mortgage sinking fund bonds. For additional information, see the
"Liquidity and Capital Resources" section of this MD&A.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Newfoundland Power, refer to the "Regulatory
Highlights" section of this MD&A.
Other Canadian Electric Utilities
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Other Canadian Electric Utilities (Unaudited) (1)
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Electricity Sales (GWh) 483 508 (25) 1,099 1,107 (8)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 63 61 2 133 131 2
-------------------------------------------------------------------------
Energy Supply Costs 40 40 - 87 89 (2)
-------------------------------------------------------------------------
Operating Expenses 7 7 - 14 14 -
-------------------------------------------------------------------------
Amortization 5 5 - 9 9 -
-------------------------------------------------------------------------
Finance Charges 4 5 (1) 9 9 -
-------------------------------------------------------------------------
Corporate Taxes 3 2 1 5 4 1
-------------------------------------------------------------------------
Earnings 4 2 2 9 6 3
-------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at Other Canadian Electric Utilities
decreased 25 GWh, or 4.9 per cent, quarter over quarter, driven by lower average
consumption mainly due to cooler-than-normal weather experienced in Ontario and
the impact of a general economic slowdown. Electricity sales decreased 8 GWh,
or 0.7 per cent, year to date compared to the same period last year, driven by
lower average consumption during the second quarter of 2009, for the reasons for
the quarter, as described above, partially offset by higher average consumption
during the first quarter of 2009 compared to the same quarter last year, due to
colder-than-normal weather experienced in Ontario and on Prince Edward Island.
Revenue: Revenue increased $2 million quarter over quarter and $2 million year
to date compared to the same period last year. Excluding an approximate $3
million ($2 million after-tax) one-time charge at FortisOntario associated with
the repayment, during the second quarter of 2008, of a refund received during
the fourth quarter of 2007 associated with cross-border transmission
interconnection agreements, revenue decreased $1 million quarter over quarter
and $1 million year to date compared to the same period last year. The impact
of lower electricity sales and the flow through to customers of lower energy
supply costs at FortisOntario was partially offset by the impact of an average
5.3 per cent increase in customer electricity rates at Maritime Electric,
effective April 1, 2009. The higher customer electricity rates at Maritime
Electric reflect an increase in the amount of energy-related costs being
collected from customers through the basic rate component of customer billings.
Earnings: Earnings were $2 million higher quarter over quarter and $3 million
higher year to date compared to the same period last year. Excluding the $2
million after-tax one-time charge at FortisOntario associated with the
repayment, during the second quarter of 2008, of the interconnection
agreement-related refund, earnings were comparable quarter over quarter and
increased $1 million year to date compared to the same period last year,
reflecting stable operating conditions.
In June 2009, FortisOntario acquired a 10 per cent interest in Grimsby Power
Inc. ("Grimsby") for approximately $1 million. Grimsby is an electric
distribution utility serving approximately 10,000 customers in a service
territory in close proximity to FortisOntario's operations in Fort Erie.
In June 2009, FortisOntario entered into an agreement to acquire Great Lakes
Power Distribution Inc., an electric distribution utility serving approximately
12,000 customers in the district of Algoma in northern Ontario, for
approximately $68 million, subject to adjustment and customary regulatory
approvals.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Maritime Electric and FortisOntario, refer to the
"Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC UTILITIES - CARIBBEAN
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulated Electric Utilities - Caribbean (1)
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008(2) Variance 2009 2008(2) Variance
-------------------------------------------------------------------------
Average
US:CDN
Exchange
Rate (3) 1.17 1.01 0.16 1.20 1.01 0.19
-------------------------------------------------------------------------
Electricity
Sales (GWh) 293 276 17 540 534 6
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 82 78 4 165 153 12
-------------------------------------------------------------------------
Energy Supply
Costs 45 64(4) (19) 91 104(4) (13)
-------------------------------------------------------------------------
Operating
Expenses 14 12 2 28 23 5
-------------------------------------------------------------------------
Amortization 9 8 1 20 15 5
-------------------------------------------------------------------------
Finance Charges 4 2 2 8 7 1
-------------------------------------------------------------------------
Corporate Taxes 1 (1) 2 1 - 1
-------------------------------------------------------------------------
Non-Controlling
Interest 2 (2) 4 4 2 2
-------------------------------------------------------------------------
Earnings 7 (5) 12 13 2 11
-------------------------------------------------------------------------
(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) Comparative 2008 electricity sales and financial results for the second
quarter and year-to-date period included financial results of Caribbean
Utilities for the three and six months ended April 30, 2008,
respectively. Up to and including the third quarter of 2008, Caribbean
Utilities' financial statements were consolidated in the financial
statements of Fortis on a two-month lag basis. In 2008, Caribbean
Utilities changed its fiscal year end from April 30th to December 31st,
eliminating the previous two-month lag in consolidating its financial
results. Therefore, electricity sales and financial results for the
second quarter and year-to-date period ended June 30, 2009 associated
with Caribbean Utilities relate to the utility's second quarter and
year-to-date period ended June 30, 2009.
(3) The reporting currency of Belize Electricity is the Belizean dollar,
which is pegged to the US dollar at BZ$2.00 equals US$1.00. The
reporting currency of Caribbean Utilities and Fortis Turks and Caicos
is the US dollar.
(4) Energy supply costs during the second quarter of 2008 included an $18
million (BZ$36 million) charge as a result of a regulatory rate
decision by the Public Utilities Commission in Belize in June 2008.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Regulated Electric Utilities - Caribbean electricity sales
increased 17 GWh, or 6.2 per cent, quarter over quarter and increased 6 GWh, or
1.1 per cent, year to date compared to the same period last year. The increases
were primarily due to seasonality at Caribbean Utilities and, to a lesser
extent, customer growth. At Caribbean Utilities, the average temperatures for
the three and six months ended June 30th are historically higher than those for
the three and six months ended April 30th. Comparative 2008 financial results
for the second quarter and year-to-date period included financial results of
Caribbean Utilities for the three and six months ended April 30, 2008,
respectively, due to the two-month lag in consolidating Caribbean Utilities'
financial results prior to the third quarter of 2008. Tempering electricity
sales growth was the negative impact of global economic conditions on
consumption by residential customers and activities in the tourism, oil,
construction and related industries, and cooler-than-normal weather conditions
in the region which reduced air-conditioning load.
Revenue: Revenue increased $4 million quarter over quarter. Excluding the
approximate $9 million favourable impact during the second quarter of 2009 of
foreign exchange associated with the translation of foreign currency-denominated
revenue, due to the strengthening of the US dollar against the Canadian dollar
compared to the same quarter last year, revenue decreased approximately $5
million quarter over quarter. Primary factors decreasing revenue included: (i)
the flow through to customers of lower energy supply costs at Caribbean
Utilities; (ii) a decrease in the value-added delivery ("VAD") component of the
average electricity rate at Belize Electricity, effective July 1, 2008,
reflecting a lower allowed rate of return on rate base assets ("ROA") as a
result of the regulator's June 2008 Final Decision; and (iii) a change in the
methodology at Belize Electricity for recording customer installation fees. The
above factors were partially offset by the impact of: (i) increased electricity
sales; (ii) an increase in the cost of power ("COP") component of the average
electricity rate at Belize Electricity, effective July 1, 2008; and (iii) a 2.4
per cent increase in basic electricity rates at Caribbean Utilities, effective
June 1, 2009.
Revenue increased $12 million year to date compared to the same period last
year. Revenue during the first quarter of 2009 was favourably impacted by
approximately $1 million associated with a favourable appeal judgment at Fortis
Turks and Caicos related to a customer rate classification matter. Excluding the
above one-time item and approximately $25 million associated with favourable
foreign currency translation, revenue decreased approximately $14 million year
to date compared to the same period last year. Primary factors decreasing
revenue included: (i) the flow through to customers of lower energy supply costs
at Caribbean Utilities and Fortis Turks and Caicos; (ii) the decrease in the
VAD component of the average electricity rate at Belize Electricity, effective
July 1, 2008; (iii) a 3.25 per cent reduction in basic electricity rates,
effective January 1, 2008, reflecting a lower allowed ROA at Caribbean
Utilities, under the terms of the Agreement in Principle with the Government of
the Cayman Islands and the subsequent new transmission and distribution ("T&D")
licence granted in April 2008; and (iv) a change in the methodology at Belize
Electricity for recording customer installation fees and the impact of refunding
certain installation fees previously collected. Customer installation fees at
Belize Electricity are now recorded as a capital contribution on the balance
sheet rather than as revenue on the statement of earnings. The above factors
were partially offset by the impact of: (i) an increase in the COP component of
the average electricity rate at Belize Electricity, effective July 1, 2008; (ii)
a 2.4 per cent increase in basic customer rates at Caribbean Utilities,
effective June 1, 2009; and (iii) increased electricity sales.
Earnings: Earnings' contribution was $12 million higher quarter over quarter.
Earnings for the second quarter of 2008 were reduced by $13 million,
representing the Corporation's approximate 70 per cent share of $18 million of
disallowed previously incurred fuel and purchased power costs as a result of the
June 2008 regulatory rate decision at Belize Electricity. Excluding the impact
of the above one-time item in 2008 and approximately $1 million associated with
favourable foreign currency translation, earnings' contribution decreased $2
million quarter over quarter. The decline was mainly due to a lower allowed ROA
at Belize Electricity, effective July 1, 2008; increased amortization costs; and
the favourable impact on energy supply costs during the second quarter of 2008
associated with the movement in deferred fuel costs at Caribbean Utilities.
Included in Caribbean Utilities' T&D licence is a new mechanism for the flow
through to customers of the cost of fuel and oil, which eliminates favourable or
adverse timing differences in fuel and oil cost recovery for reporting periods
subsequent to April 30, 2008. The decrease in earnings' contribution quarter
over quarter was partially offset by the impact of higher electricity sales and
lower operating expenses.
Earnings' contribution was $11 million higher year to date compared to the same
period last year. Excluding: (i) the one-time item in the second quarter of
2008 as described above; (ii) an approximate $1 million one-time favourable
adjustment to energy supply costs associated with a change in the methodology
for accruing unbilled fuel factor revenue at Fortis Turks and Caicos during the
first quarter of 2009; (iii) approximately $1 million associated with a
favourable appeal judgment at Fortis Turks and Caicos related to a customer rate
classification matter during the first quarter of 2009; and (iv) approximately
$2 million associated with favourable foreign currency translation, earnings'
contribution decreased $6 million year to date compared to the same period last
year. The decline was mainly due to a lower allowed ROA at Belize Electricity,
effective July 1, 2008, increased amortization costs and the favourable impact
on energy supply costs during the first half of 2008 associated with the
movement in deferred fuel costs at Caribbean Utilities, as described above for
the quarter. The decrease was partially offset by the impact of higher
electricity sales, lower operating expenses and decreased finance charges.
Excluding foreign currency translation impacts, amortization costs increased
approximately $1 million quarter over quarter and $2 million year to date
compared to the same period last year due to the impact of continued investment
in capital assets.
Excluding foreign currency translation impacts, operating expenses decreased
approximately $1 million quarter over quarter and year to date compared to the
same period last year, primarily due to the timing of maintenance expenses and
lower general and administrative expenses.
Excluding foreign currency translation impacts, finance charges were comparable
quarter over quarter and decreased approximately $1 million year to date
compared to the same period last year. The decrease was mainly due to increased
capitalized finance costs at Caribbean Utilities, due to a change in the
utility's methodology for capitalizing finance costs associated with capital
assets under construction, as prescribed by the regulator.
Caribbean Utilities met a record peak of approximately 96 MW in July 2009 and
Fortis Turks and Caicos met a record peak of approximately 29.5 MW in July 2009.
In May 2009, Fortis Turks and Caicos also commissioned two diesel-generating
units, increasing the Company's generating capacity by 6 MW to 54 MW. Fortis
Turks and Caicos has also entered into an agreement with a supplier to purchase
two diesel-generating engines with a combined capacity of approximately 17.5 MW
for approximately US$12 million (CDN$13 million) for delivery in April 2010 and
January 2011.
Belize Electricity's energy supply and firm capacity from Comision Federal de
Electricidad ("CFE") of Mexico was reduced in recent months due to repairs being
performed on certain major generating plants owned by CFE. As a result, Belize
Electricity has increased its energy purchases from Belize Aquaculture Limited
and increased its use of in-house generation in order to meet customer energy
demands with little to no reserve capacity remaining available.
Caribbean Utilities privately placed 15-year US$40 million 7.50% senior
unsecured notes with US$30 million placed in May 2009 and US$10 million placed
in July 2009. For additional information, see the "Liquidity and Capital
Resources" section of this MD&A.
On July 22, 2009, Fortis acquired, through a wholly owned subsidiary, 768,200
Class A Ordinary Shares of Caribbean Utilities at a price of US$8.00 per share.
The shares were acquired by Fortis pursuant to a private agreement which
resulted in Fortis increasing its controlling ownership in Caribbean Utilities
by 2.7 per cent to 59.5 per cent.
For additional information on the nature of regulation and material regulatory
decisions and applications pertaining to Belize Electricity, Caribbean Utilities
and Fortis Turks and Caicos, refer to the "Regulatory Highlights" section of
this MD&A.
NON-REGULATED - FORTIS GENERATION
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Generation (1)
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Energy Sales (GWh) 141 312 (171) 398 600 (202)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 9 22 (13) 25 41 (16)
-------------------------------------------------------------------------
Energy Supply Costs - 2 (2) 1 4 (3)
-------------------------------------------------------------------------
Operating Expenses 2 4 (2) 6 8 (2)
-------------------------------------------------------------------------
Amortization 2 3 (1) 4 5 (1)
-------------------------------------------------------------------------
Finance Charges 1 2 (1) 2 4 (2)
-------------------------------------------------------------------------
Corporate Taxes - 2 (2) 2 5 (3)
-------------------------------------------------------------------------
Non-Controlling Interest 1 2 (1) 1 2 (1)
-------------------------------------------------------------------------
Earnings 3 7 (4) 9 13 (4)
-------------------------------------------------------------------------
(1) Includes the operations of non-regulated generating assets in Belize,
Ontario, central Newfoundland, British Columbia and Upper New York
State. Prior to May 1, 2009, financial results reflected earnings'
contribution associated with the Corporation's 75-MW water-right
entitlement on the Niagara River in Ontario under the Niagara Exchange
Agreement related to the Rankine hydroelectric generating facility.
The Niagara Exchange Agreement expired on April 30, 2009, in accordance
with its terms. Prior to February 13, 2009, the financial results of
the hydroelectric generation operations in central Newfoundland were
consolidated in the financial statements of Fortis. As of February 13,
2009, the financial results of the generation operations in central
Newfoundland have been recorded in the financial statements of Fortis
on an equity basis, due to the Corporation no longer having control
over the generation operations as a result of the expropriation of the
related assets by the Government of Newfoundland and Labrador. The
change in the method of accounting did not have a material impact on
segmented or consolidated earnings. Equity income for 2009 related to
central Newfoundland operations is being recorded in revenue. For a
further discussion of this matter, refer to the "Critical Accounting
Estimates - Contingencies" section of this MD&A.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Sales: Non-Regulated - Fortis Generation energy sales decreased 171 GWh,
or 54.8 per cent, quarter over quarter and decreased 202 GWh, or 33.7 per cent,
year to date compared to the same period last year. As anticipated, energy
sales decreased 109 GWh and 112 GWh for the second quarter and year to date,
respectively, due to the expiration, on April 30, 2009, of the power-for-water
exchange agreement related to the Rankine hydroelectric generating facility in
Ontario. In addition, energy sales for the first half of 2009 included energy
sales associated with the generation operations in central Newfoundland for only
11/2 months compared to a full six months in 2008, due to the change to the
equity method of accounting for these operations in February 2009 necessitated
by the actions of the Government of Newfoundland and Labrador related to its
expropriation of Newfoundland-based assets of AbitibiBowater Inc., formerly
Abitibi-Consolidated Company of Canada ("Abitibi"). The decrease in energy sales
quarter over quarter, as described above, was partially offset by the impact of
higher production in Upper New York State. The decrease in energy sales year to
date compared to the same period last year, as described above, was coupled with
the impact of lower production in Upper New York State, partially offset by the
impact of higher production in Belize. Production levels were primarily a
function of rainfall levels. At July 31, 2009, the Chalillo reservoir in Belize
was at its full-supply level.
Revenue: Revenue was $13 million lower quarter over quarter and $16 million
lower year to date compared to the same period in 2008. The primary factors
decreasing revenue were: (i) the loss of revenue subsequent to the expiration of
the power-for-water exchange agreement related to the Rankine hydroelectric
generating facility, as described above; (ii) the impact of changing to the
equity method of accounting for the financial results of the hydroelectric
generation operations in central Newfoundland during the first quarter of 2009,
as described above; (iii) lower average wholesale market energy prices per
megawatt hour ("MWh") in Ontario, which were $18.39 for April 2009 compared to
$49.00 for April 2008 and were $36.83 for January through April 2009 compared to
$49.70 for the same period in 2008; and (iv) lower average wholesale market
energy prices per MWh in Upper New York State, which were US$33.36 for the
second quarter of 2009 compared to US$81.26 for the same quarter in 2008 and
were US$39.07 for the first half of 2009 compared to US$77.06 for the first half
of 2008. Revenue also decreased year to date compared to the same period last
year due to the impact of lower production in Upper New York State, partially
offset by the impact of increased production in Belize. Revenue for the quarter
and year to date, however, was favourably impacted by approximately $1 million
and $2 million, respectively, of foreign exchange associated with the
translation of foreign currency-denominated revenue, due to the strengthening of
the US dollar against the Canadian dollar compared to the same periods last
year.
Earnings: Earnings decreased $4 million quarter over quarter and $4 million year
to date compared to the same period last year. The decreases primarily related
to the loss of earnings subsequent to the expiration of the power-for-water
exchange agreement related to the Rankine hydroelectric generating facility and
lower average wholesale market energy prices in Upper New York State and
Ontario. Year to date compared to the same period last year, earnings also
decreased due to the impact of lower production in Upper New York State,
partially offset by the impact of increased production in Belize. Earnings for
the quarter and year to date, however, were favorably impacted by approximately
$1 million associated with foreign currency translation. Earnings' contribution
associated with the Rankine hydroelectric generating facility were $0.2 million
for the second quarter and $3.5 million year to date compared to $3.6 million
and $7.5 million for the respective periods in 2008.
NON-REGULATED - FORTIS PROPERTIES
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Hospitality Revenue 42 39 3 73 68 5
-------------------------------------------------------------------------
Real Estate Revenue 16 15 1 32 31 1
-------------------------------------------------------------------------
Total Revenue 58 54 4 105 99 6
-------------------------------------------------------------------------
Operating Expenses 38 35 3 72 66 6
-------------------------------------------------------------------------
Amortization 4 3 1 8 7 1
-------------------------------------------------------------------------
Finance Charges 5 6 (1) 11 12 (1)
-------------------------------------------------------------------------
Corporate Taxes 3 3 - 4 4 -
-------------------------------------------------------------------------
Earnings 8 7 1 10 10 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue: Hospitality revenue was $3 million higher quarter over quarter and $5
million higher year to date compared to the same period last year, driven by
revenue contribution from the Sheraton Hotel Newfoundland, which was acquired in
November 2008, and the 214-room Holiday Inn Select in Windsor, Ontario, which
was acquired in April 2009 for $7 million, partially offset by decreased revenue
from operations in Atlantic Canada, Ontario and western Canada.
Revenue per available room was $83.15 for the second quarter compared to $87.54
for the same quarter in 2008, and was $74.03 year to date compared to $77.68 for
the same period last year. The decreases were mainly due to lower hotel
occupancies in all of the Company's operating regions, the most significant of
which were experienced in western Canada.
Real Estate revenue was $1 million higher quarter over quarter and year to date
compared to the same period last year, primarily due to one-time lease
termination fees associated with a tenant in New Brunswick. The occupancy rate
of the Real Estate Division was 95.9 per cent as at June 30, 2009 compared to
96.7 per cent as at June 30, 2008. The decrease in the occupancy rate was
primarily associated with a property in rural Newfoundland.
Earnings: Earnings were $1 million higher quarter over quarter, driven by
increased contribution from the Real Estate Division combined with lower
corporate operating expenses, partially offset by lower contribution from the
Hospitality Division mainly caused by lower hotel occupancies. Earnings were
comparable year to date with the same period last year. Increased contribution
from the Real Estate Division and lower corporate operating expenses were
largely offset by lower contribution from the Hospitality Division, for the
reason described above for the quarter.
Operating expenses were $3 million higher quarter over quarter and $6 million
higher year to date compared to the same period last year. The increases were
primarily related to the Sheraton Hotel Newfoundland, including non-recurring
transitional operating costs incurred during the first quarter of 2009, and the
Holiday Inn Select in Windsor, partially offset by lower corporate operating
expenses and lower operating expenses incurred at the Real Estate Division. The
decrease in operating expenses incurred at the Real Estate Division mainly
related to the reclassification to amortization costs during 2009 of the
depreciation of certain capitalized major operating expenses recoverable from
tenants.
CORPORATE AND OTHER
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate and Other (1)
Financial Highlights (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Revenue 7 5 2 14 12 2
-------------------------------------------------------------------------
Operating Expenses 4 3 1 7 6 1
-------------------------------------------------------------------------
Amortization 3 1 2 5 4 1
-------------------------------------------------------------------------
Finance Charges (2) 18 20 (2) 37 41 (4)
-------------------------------------------------------------------------
Corporate Tax Recovery (5) (4) (1) (9) (9) -
-------------------------------------------------------------------------
Preference share dividends 5 3 2 9 4 5
-------------------------------------------------------------------------
Net Corporate and Other
Expenses (18) (18) - (35) (34) (1)
-------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated
Terasen corporate-related activities and the financial results of
Terasen's 30 per cent ownership interest in CWLP and of Terasen's non-
regulated wholly owned subsidiary Terasen Energy Services Inc.
(2) Includes dividends on preference shares classified as long-term
liabilities
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue: Revenue was $2 million higher quarter over quarter and year to date
compared to the same period last year, driven by higher inter-company interest
revenue due to increased inter-company lending.
Net Corporate and Other Expenses: Net corporate and other expenses were
comparable quarter over quarter and were $1 million higher year to date compared
to the same period last year. Year to date compared to the same period last
year, an increase in preference share dividends, due to the issuance of First
Preference Shares, Series G during the second quarter of 2008, and lower
earnings' contribution from CustomerWorks Limited Partnership ("CWLP") were
partially offset by lower finance charges and higher inter-company interest
revenue.
Finance charges decreased quarter over quarter and year to date compared to the
same period last year as a result of lower debt levels and lower interest rates
charged on credit facility borrowings, partially offset by the unfavourable
impact of foreign exchange associated with the translation of US
dollar-denominated interest expense. In December 2008, Fortis completed a $300
million common share issue, the net proceeds of which were primarily used to
repay short-term debt incurred to repay maturing long-term debt.
In July 2009, Fortis issued 30-year $200 million 6.51% unsecured debentures the
net proceeds of which were used to repay in full the indebtedness outstanding
under the Corporation's committed credit facility and for general corporate
purposes.
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
are summarized as follows:
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Nature of Regulation
---------------------------------------------------------------------------
Allowed Returns (%) Supportive Features
Allowed ------------------ --------------------
Common Future or Historical
Regulated Regulatory Equity Test Year Used to
Utility Authority (%) 2007 2008 2009 Set Rates
---------------------------------------------------------------------------
ROE Cost of Service
TGI British ------------------ ("COS")/ROE
Columbia 35 8.37 8.62 8.47 Performance-based
Utilities rate-setting
Commission ("PBR") mechanism
("BCUC") through 2009: TGI:
50/50 sharing of
earnings above or
below the allowed
ROE
TGVI BCUC 40 9.07 9.32 9.17 TGVI: 100 per cent
retention of
earnings from
lower-than-
forecasted
operating and
maintenance costs
but no relief from
increased operating
and maintenance
costs
ROE automatic
adjustment formula
tied to long-term
Canada bond yields
-------------------
Future Test Year
---------------------------------------------------------------------------
FortisBC BCUC 40 8.77 9.02 8.87 COS/ROE
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 automatic
adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Fortis Alberta 37 8.51 8.75 8.51(1) COS/ROE
Alberta Utilities
Commission ROE automatic
("AUC") adjustment formula
tied to long-term
Canada bond yields
--------------------
Future Test Year
---------------------------------------------------------------------------
Newfound- Newfoundland 45 8.60 8.95 8.95 COS/ROE
land and Labrador +/- +/- +/-
Power Board of 50 bps 50 bps 50 bps ROE automatic
Commissioners adjustment formula
of Public tied to long-term
Utilities Canada bond yields
("PUB") --------------------
Future Test Year
---------------------------------------------------------------------------
Maritime Island 40 10.25 10.00 9.75 COS/ROE
Electric Regulatory and
Appeals
Commission --------------------
("IRAC") Future Test Year
---------------------------------------------------------------------------
Fortis- Ontario Energy 43.3 9.00 9.00 8.01 Canadian Niagara
Ontario Board ("OEB") Power - COS/ROE
(Canadian
Niagara Power) Cornwall Electric
- Price cap with
Franchise commodity cost
Agreement flow through
(Cornwall --------------------
Electric) Future Test Year
- Beginning in 2009
---------------------------------------------------------------------------
Belize Public ROA Four-year COS/ROA
Electri- Utilities ------------------- agreements
city Commission N/A 10.00- 10.00 10.00
("PUC") 15.00 (2) Additional costs
in the event of a
hurricane would be
deferred and the
Company may apply
for future recovery
in customer rates.
--------------------
Future Test Year
---------------------------------------------------------------------------
Caribbean Electricity N/A 15.00 9.00- 9.00- COS/ROA
Utilities Regulatory 11.00 11.00
Authority Rate-cap adjustment
("ERA") mechanism based on
published consumer
price indices
Under the new T&D
licence, the
Company may apply
for a special
additional rate to
customers in the
event of a disaster,
including a
hurricane.
--------------------
Historical Test
Year
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Fortis Utility N/A 17.50 17.50 17.50 COS/ROA
Turks makes annual (3) (3) (3)
and filings with If the actual ROA
Caicos the Energy is lower than the
Commissioner 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
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(1) Interim ROE pending the outcome of the AUC's 2009 Generic Cost of
Capital Proceeding
(2) Based on the June 2008 Final Decision related to Belize Electricity's
2008/2009 Rate Application
(3) Amount provided under licence. Actual ROAs achieved in 2007 and 2008
were significantly lower than the ROA allowed under the licence due to
significant investment occurring at the utility.
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Material Regulatory Decisions and Applications
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Regulated Utility Summary Description
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TGI/TGVI - Every three months, TGI and TGVI review natural gas
and propane commodity prices with the BCUC in order
to ensure the flow-through rates charged to customers
are sufficient to cover the cost of purchasing
natural gas and propane. As approved by the BCUC,
the commodity rate for natural gas was unchanged
during the first quarter of 2009 while the commodity
rate for propane decreased, effective January 1,
2009. Effective April 1, 2009, the BCUC approved
decreases in the commodity rates for natural gas and
propane. Effective July 1, 2009, the BCUC approved
the commodity rate for natural gas as unchanged for
customers in most service regions and approved an
increase in the commodity rate for propane for
customers in Revelstoke. The commodity cost of
natural gas and propane is flowed through to
customers without markup.
- In December 2008, the BCUC approved a basic customer
delivery rate increase of approximately 6 per cent at
TGI and approved basic customer delivery rate
increases up to 5 per cent at TGVI based on customer
rate class. Basic customer delivery rates for 2009
reflect the decrease in the allowed ROE for 2009 at
TGI and TGVI to 8.47 per cent and 9.17 per cent,
respectively, resulting from the application of
automatic ROE adjustment mechanisms.
- In March 2009, TGI received approval for its
application with the BCUC to perform extensive
rehabilitation of certain underwater transmission
pipeline crossings of the South Arm of the Fraser
River, serving Vancouver and Richmond. The project
is expected to be completed in 2010 for a total cost
of approximately $27 million.
- In April 2009, TGI received approval from the BCUC
for its new $41.5 million Energy Efficiency and
Conservation Program to provide customers with
enhanced tools and incentives to manage their natural
gas consumption, reduce their energy costs and lower
their greenhouse gas emissions. The program will
begin during summer 2009.
- In June 2009, the BCUC approved TGI's application
requesting to sell liquefied natural gas ("LNG") as a
transportation fuel source for fleet vehicles.
- In May 2009, the Terasen Gas companies filed an
application with the BCUC requesting a review of the
current generic allowed ROE adjustment mechanism and
the deemed equity component of the capital structure
for TGI. The application contemplates an increase in
TGI's allowed ROE to 11 per cent from 8.47 per cent,
effective July 1, 2009, and an increase in the
allowed common equity component of the capital
structure to 40 per cent from 35 per cent, effective
January 1, 2010. No change was requested in the
risk-premium spread of 70 basis points over TGI's
allowed ROE in determining TGVI's allowed ROE.
- In June 2009, TGI applied to the BCUC for in-sourcing
of core elements of its customer care services and
for implementation of a new customer information
system. If approved, the new model would be in place
effective January 2012 at a total expected capital
cost of approximately $145 million. TGI has requested
a decision on this project by the end of 2009.
- Effective June 1, 2009, the BCUC approved an average
12 per cent decrease in basic customer delivery rates
at TGWI. Effective July 1, 2009, the BCUC also
approved an approximate 10 per cent decrease in
commodity rates at TGWI.
- In June 2009, TGI and TGVI each filed with the BCUC
two-year revenue requirements applications for 2010
and 2011. The current PBR agreements at TGI and TGVI
expire on December 31, 2009. The rate applications
will be updated to reflect the amounts to be approved
by the BCUC with respect to an increase in the deemed
equity level and allowed ROE as filed by TGI with the
BCUC in May 2009, as described above. TGI's
application assumes forecast average rate base of
approximately $2,536 million and $2,620 million for
2010 and 2011, respectively, while TGVI's application
assumes forecast average rate base of approximately
$555 million and $730 million for 2010 and 2011,
respectively. The expected impact on TGI basic
customer delivery rates for 2010 and 2011, before any
effect of an increase in the deemed equity level and
the allowed ROE, is an increase of approximately
3 per cent and 2 per cent, respectively. TGVI is
requesting basic customer delivery rates remain
unchanged for the two-year period beginning January
1, 2010.
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FortisBC - In December 2008, the BCUC approved the Company's
2009 Revenue Requirements Application, resulting in a
general rate increase of 4.6 per cent, effective
January 1, 2009. The rate increase is primarily the
result of the Company's capital expenditure program
and higher power purchases driven by customer growth
and increased electricity demand. Rates for 2009
reflect an allowed ROE of 8.87 per cent as a result
of the application of the automatic ROE adjustment
mechanism. The approval of the 2009 Revenue
Requirements Application also included an extension
of the PBR mechanism for the years 2009 through 2011
under terms similar to the previous PBR agreement,
except annual gross operating and maintenance
expenses, before capitalized overhead, will be set by
a formula incorporating customer growth and
inflation, i.e., the consumer price index ("CPI") for
British Columbia minus a productivity improvement
factor ("PIF") of 3 per cent in 2009, 1.5 per cent
in 2010 and 1.5 per cent in 2011. Should inflation
be in excess of 3 per cent, the excess is to be added
to the PIF, which effectively caps the CPI at 3 per
cent.
- In February 2009, the BCUC issued its decision on
FortisBC's 2009 and 2010 Capital Expenditure Plan.
Total gross capital expenditures of $165 million and
$156 million were approved for 2009 and 2010,
respectively. An additional $16 million of capital
expenditures is subject to further regulatory
processes.
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FortisAlberta - In June 2008, the AUC ruled that a review of ROE
levels, adjustment mechanisms and utility capital
structures in a generic proceeding would be
appropriate. In July 2008, the AUC issued its notice
of application, preliminary scoping document and
minimum filing requirements for the 2009 Generic Cost
of Capital Proceeding. The proceeding applies to all
gas, electric and pipeline utilities in Alberta that
are regulated by the AUC.
- In November 2008, FortisAlberta submitted its
evidence with respect to the 2009 Generic Cost of
Capital Proceeding as requested by the AUC.
Oral hearings took place in May and June 2009 and an
AUC order is expected before the end of 2009.
- In December 2008, FortisAlberta received regulatory
approval for its 2009 distribution rates to recover
approved distribution costs. The result was a
distribution rate increase of 8.6 per cent, effective
January 1, 2009. The rate increase was slightly
higher than the rate increase of 7.3 per cent
contemplated in the 2008/2009 Negotiated Settlement
Agreement ("NSA"), due to the deferred recovery in
customer rates in 2009 of the increase in the allowed
ROE to 8.75 per cent in 2008. The approved rates for
2009 also reflect the impact of the Company's union
agreement, which was settled after the 2008/2009 NSA
was approved. As directed by the AUC, the Company is
to continue using the 2007 allowed ROE of 8.51 per
cent for 2009, pending the outcome of the 2009
Generic Cost of Capital Proceeding.
- In June 2009, FortisAlberta filed a comprehensive
two-year distribution revenue requirements
application for 2010 and 2011. For both years, the
application assumes an interim allowed ROE of 8.75
per cent with a deemed equity level of 37 per cent,
pending the outcome of the current Generic Cost of
Capital Proceeding. The application also forecasts
average rate base of approximately $1,538 million and
$1,724 million for 2010 and 2011, respectively. The
expected impact on the distribution component of
customer rates for 2010 and 2011 is an average
increase of 13.3 per cent and 14.9 per cent,
respectively. FortisAlberta anticipates a hearing in
late 2009, a regulatory decision by the AUC to be
received in spring 2010 and customer rates approved
effective summer 2010. An application for interim
rates will be made in fall 2009.
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Newfoundland - In November 2008, the PUB approved, as filed, the
Power Company's 2009 Capital Budget Application for
approximately $62 million, with approximately half of
the proposed capital expenditures relating to
replacing aged and deteriorated components of the
electricity system. In July 2009, Newfoundland Power
filed a supplemental application to its 2009 Capital
Budget Application requesting an additional $0.7
million in capital spending, which was approved by
the PUC on July 27, 2009.
- The Company's allowed ROE of 8.95 per cent remains
unchanged for 2009 and, consequently, there has been
no change in basic customer rates for 2009.
- Effective July 1, 2009, the PUB approved an overall
average decrease in customer electricity rates of
approximately 6.6 per cent, reflecting the flow
through to customers, by operation of the Rate
Stabilization Account, of variances in the cost of
fuel used to generate electricity that Newfoundland
Hydro sells to Newfoundland Power. The decrease in
customer rates will have no impact on Newfoundland
Power's earnings in 2009.
- In May 2009, Newfoundland Power filed a 2010 General
Rate Application, seeking approval for an overall
average increase in basic customer electricity rates
of approximately 6.1 per cent, effective January 1,
2010. The application seeks an increase in the
allowed ROE from 8.95 per cent to 11 per cent for
2010 on an equity level of approximately 45 per cent.
The application also forecasts average rate base of
approximately $867 million for 2010. A hearing on
the application is expected in fall 2009.
- In June 2009, Newfoundland Power filed its 2010
Capital Budget Application with the PUB for
approximately $65 million.
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Maritime - In March 2009, IRAC approved Maritime Electric's 2009
Electric Rate Application, which resulted in an increase in
the amount of energy-related costs being collected
from customers through the basic rate component of
customer billings, effective April 1, 2009. The
increase in the reference cost of energy in basic
rates from 6.73 cents per kilowatt hour ("kWh") to
7.7 cents per kWh results in a decrease in the amount
of energy costs to be collected from customers
through the operation of the Energy Cost Adjustment
Mechanism ("ECAM"). Additionally, IRAC approved the
deferral of New Brunswick Power Point Lepreau Nuclear
Generating Station replacement energy costs for 2009
and an increase in the amortization period of the
ECAM to 12 months, effective April 1, 2009. IRAC
also approved, as filed, a maximum allowed ROE of
9.75 per cent for 2009, down from an allowed ROE of
10.00 per cent for 2008. The overall impact on
residential customer rates for 2009 is an increase of
5.3 per cent based on average consumption of 650 kWh
per month.
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FortisOntario - In August 2008, Canadian Niagara Power filed a 2009
Cost of Service Application ("2009 Application")
requesting the rebasing of distribution rates using
2009 as a forward test year. The 2009 Application
assumed a deemed capital structure of 56.7 per cent
debt and 43.3 per cent equity and, as required by the
OEB, reflected a preliminary ROE of 8.39 per cent.
The application proposed distribution rate increases
of 4.9 per cent, 9.4 per cent and 7.1 per cent for
Fort Erie, Gananoque and Port Colborne, respectively,
effective May 1, 2009. The proposed increases were
primarily driven by the impact of distribution system
upgrades.
- In March 2009, the OEB announced that it was
initiating a consultative process with utilities in
Ontario that it regulates to help the OEB determine
whether current economic and financial market
conditions warrant an adjustment to any cost of
capital parameter values determined in accordance
with current established methodology. In June 2009,
the OEB issued a letter indicating that it has
decided not to change the parameters for 2009 but
will hold a stakeholder conference in September 2009
to review the cost of capital policy for future
years.
- In April 2009, the OEB issued an Interim Rate Order
declaring Canadian Niagara Power's current
distribution electricity rates to continue as interim
rates, effective May 1, 2009.
- In July 2009, the OEB issued its Decision on the 2009
Application for Fort Erie and Gananoque. The Decision
is effective May 1, 2009 with impact on customer
billings commencing September 1, 2009. Foregone
revenue from May 1, 2009 through August 31, 2009 will
be recovered from customers through a rate rider in
effect from September 1, 2009 through April 30, 2010.
The Decision confirmed a deemed capital structure
consistent with that assumed in the 2009 Application,
approved an allowed ROE of 8.01 per cent for 2009 and
approved all forecast capital expenditures and
significantly all forecast operating expenses, as
filed. Canadian Niagara Power expects to file a draft
rate order in August 2009 reflecting the outcome of
the Decision. A decision on Port Colborne's rates is
expected in fall 2009.
---------------------------------------------------------------------------
Belize - In June 2008, the PUC issued its Final Decision on
Electricity Belize Electricity's 2008/2009 Rate Application,
which rejected most of the recommendations of a PUC-
appointed Independent Expert engaged to review the
PUC's Initial Decision on Belize Electricity's
2008/2009 Rate Application and failed to increase the
overall average electricity rate as requested in the
application. The PUC also ordered a BZ$36 million
retroactive adjustment associated with Belize
Electricity's prior years' financial results. The
adjustment, in substance, represented the
disallowance of previously incurred fuel and
purchased power costs. The PUC also reduced Belize
Electricity's targeted allowed ROA to 10 per cent
from 12 per cent through a reduction in the VAD
component of the average electricity rate. As a
direct result of the June 2008 Final Decision, Belize
Electricity recorded an $18 million (BZ$36 million)
charge ($13 million of which was the Corporation's
share) to energy supply costs during the second
quarter of 2008. The Final Decision does not impact
the Corporation's hydroelectric generation operations
conducted in Belize Electric Company Limited
("BECOL").
- The Final Decision also proposed the use of an
automatic mechanism, to be finalized by the PUC, to
adjust monthly, on a two-month lag basis, the cost of
power component of the rate to reflect actual costs
of power. The automatic adjustment mechanism, which
was retroactive effective September 1, 2008, allows
for the collection from, or rebate to, customers of
actual costs of power which vary from a reference
cost of power by more than a threshold of 10 per
cent.
- In February 2009, the PUC amended the Final Decision
on Belize Electricity's 2008/2009 Rate Application
(the "Amendment"), effective for the period from
January 1, 2009 through June 30, 2009. The Amendment
provides for an increase in the VAD component of the
average electricity rate to allow Belize Electricity
to earn a targeted allowed ROA of 12 per cent but
reduces the reference COP component of the average
electricity rate, due to an overall decline in the
cost of power. The Amendment, therefore, allows for
an overall decrease in the average electricity rate
from BZ44.1 cents per kWh to BZ37.5 cents per kWh.
The Amendment also provides for a lower regulated
asset value upon which the allowed ROA is calculated,
while increasing operating expenses by the same
amount, and reduces depreciation, taxes and fees and
the related revenue requirement.
- In April 2009, Belize Electricity filed its Annual
Tariff Review Application for the annual tariff
period from July 1, 2009 to June 30, 2010 ("2009/2010
Rate Application") proposing a 6 per cent decrease in
the average electricity rate, as well as a reversal
of the BZ$36 million charge described above. The PUC
has not accepted the 2009/2010 Rate Application on
the grounds that an Annual Tariff Review Proceeding
is not in effect.
- Changes made in electricity legislation by the
Government of Belize and the PUC, and the June 2008
Final Decision and Amendment, which were based on the
changed legislation, have been judicially challenged
by Belize Electricity in several proceedings.
The judicial process is ongoing with interim rulings,
judgments and appeals. The timing or likely final
outcome of the proceedings is indeterminable at this
time. However, the Supreme Court of Belize has
approved an injunction against the Amendment until
Belize Electricity's appeal of the June 2008 Final
Decision has been heard in court, which is currently
scheduled for October 2009. In addition, Belize
Electricity's appeal of the Supreme Court of Belize's
previous decision to uphold certain changes made in
electricity legislation by the Government of Belize
and the PUC was dismissed in June 2009.
- The Minister of Public Utilities of Belize recently
issued a statutory instrument purporting to declare
providers of electricity generation and water
services, including BECOL, as public utility
providers within the meaning of the Public Utilities
Commission Act as of May 1, 2009. Fortis is
currently assessing the statutory instrument and its
impact on previously negotiated and PUC-approved
power purchase agreements.
---------------------------------------------------------------------------
Caribbean - In January 2009, a revised Five-Year Capital
Utilities Investment Plan ("CIP") totalling US$246 million was
submitted to the ERA. In March 2009, the ERA approved
the Company's 2009 CIP of US$48 million. Capital
investment relating to 2010-2013 is still under
review by the ERA.
- In January 2009, Caribbean Utilities announced a
customer-owned renewable energy program. The program
allows customers on Grand Cayman to connect renewable
energy systems to the Company's distribution system
and to generate their own power from renewable energy
while remaining connected to Caribbean Utilities'
electricity grid. The Company has received a number
of interested enquiries.
- In April 2009, Caribbean Utilities submitted its bid
to install 16 MW of generation in May 2012 and
another 16 MW of generation in May 2013. There was
one other bidder for the 32 MW of generation.
- The ERA approved a 2.4 per cent increase in basic
customer electricity rates, effective June 1, 2009,
in accordance with the rate adjustment mechanism
provided under Caribbean Utilities' T&D licence.
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Fortis Turks - In March 2009, Fortis Turks and Caicos submitted its
and Caicos 2008 annual regulatory filing outlining the Company's
performance in 2008 and its capital expansion plans
for 2009.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between June 30, 2009 and December 31, 2008.
---------------------------------------------------------------------------
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Fortis Inc.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between June 30, 2009 and December 31, 2008
---------------------------------------------------------------------------
Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
---------------------------------------------------------------------------
Cash and cash 71 The increase was primarily due to cash on
equivalents hand associated with partial proceeds from
the $105 million debenture offering at
FortisBC in June 2009, which were used to
help repay $50 million of debentures that
matured in July 2009, and higher cash
balances at the Terasen Gas companies.
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Accounts receivable (232) The decrease was primarily due to the impact
of a seasonal decrease in sales, driven by
the Terasen Gas companies, and the impact of
lower fuel factor billings at Caribbean
Utilities and Fortis Turks and Caicos
associated with a decline in fuel prices.
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Regulatory assets 587 The increase was primarily due to the result
- current and of recording $538 million in regulatory
long-term assets as at June 30, 2009, associated with
the recognition of future income taxes upon
adoption of amended Section 3465, Income
Taxes, effective January 1, 2009. The
remainder of the increase was mainly due to
the regulatory deferral associated with the
change in the fair market value of the gas
commodity swap and option contracts at the
Terasen Gas companies and the deferral of
Point Lepreau energy replacement costs at
Maritime Electric. The increase was
partially offset by the impact of the
deferral of amounts collected in customer
rates in excess of the actual commodity cost
of natural gas at the Terasen Gas companies
during the first half of 2009.
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Inventories (95) The decrease was driven by the normal
seasonal reduction of gas in storage at the
Terasen Gas companies.
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Other assets (58) The decrease was driven by a net $61 million
reduction associated with the change to the
equity method of accounting of the
Corporation's interest in the Exploits River
Hydro Partnership ("Exploits Partnership"),
effective February 13, 2009. Previously,
the financial results of the Exploits
Partnership were consolidated in the
financial statements of the Corporation.
Refer to the "Critical Accounting Estimates
- Contingencies" section of this MD&A for a
further discussion of the Exploits
Partnership.
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Utility capital assets 269 The increase primarily related to $474
million invested in electricity and gas
systems, partially offset by amortization
and customer contributions for the six
months ended June 30, 2009 combined with the
impact of foreign exchange on the
translation of foreign currency-denominated
utility capital assets.
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Short-term borrowings (240) The decrease was driven by the repayment of
short-term borrowings by TGI with partial
proceeds from the issuance of long-term debt
combined with lower borrowings at the
Terasen Gas companies due to seasonality of
operations.
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Accounts payable and (70) The decrease was driven by lower amounts
accrued charges owing for purchased gas and purchased power
at the Terasen Gas companies and
Newfoundland Power, respectively, due to
seasonality of operations, partially offset
by a $76 million increase associated with
the change in the fair market value of gas
commodity swap and option contracts at the
Terasen Gas companies.
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Income taxes payable (49) The decrease was mainly due to the timing of
income tax payments at the Terasen Gas
companies and Newfoundland Power.
---------------------------------------------------------------------------
Regulatory liabilities 76 The increase was primarily due to the result
- current and of recording $49 million in regulatory
long-term liabilities as at June 30, 2009, associated
with the recognition of future income taxes
upon adoption of amended Section 3465,
Income Taxes, effective January 1, 2009.
The remainder of the increase was mainly due
to the deferral of earnings in excess of the
allowed earnings at TGVI through operation
of the revenue deficiency deferral account,
the lower cost of fuel and purchased power
at Belize Electricity during the first half
of 2009 compared to amounts collected in
customer rates during the same time period
and the deferral of the margin impact of
actual customer consumption exceeding
forecast consumption at the Terasen Gas
companies.
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Future income tax 478 The increase was primarily due to the
liabilities recognition of future income taxes upon
- current and adoption of amended Section 3465, Income
long-term Taxes, effective January 1, 2009.
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Deferred credits 29 The increase was primarily due to the
reclassification of $19 million to future
income taxes upon adoption of amended
Section 3465, Income Taxes, effective
January 1, 2009. Such taxes were previously
netted against other post-employment benefit
obligations at the Terasen Gas companies.
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Long-term debt and 269 The increase was primarily due to the
capital lease issuance of long-term debt and a net
obligations (including $57 million increase in committed credit
current portion) facility borrowings, partially offset by a
$61 million decrease associated with the
change to the equity method of accounting of
the Corporation's interest in the Exploits
Partnership, effective February 13, 2009;
regularly scheduled debt repayments and debt
maturities; and the impact of foreign
exchange on the translation of foreign
currency-denominated debt. Previously, the
financial results of the Exploits
Partnership were consolidated in the
financial statements of the Corporation.
Refer to the "Critical Accounting Estimates
- Contingencies" section of this MD&A for a
further discussion of the Exploits
Partnership.
The issuance of long-term debt during the
first half of 2009, primarily to repay
committed credit-facility borrowings, short-
term borrowings and maturing debt, was
comprised of a $100 million debenture
offering by TGI, a $100 million debenture
offering by FortisAlberta, a $65 million
bond offering by Newfoundland Power, a US$30
million note offering by Caribbean Utilities
and a $105 million debenture offering by
FortisBC.
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Shareholders' equity 74 The increase was mainly due to net earnings
applicable to common shares reported for the
six months ended June 30, 2009, less common
share dividends. The remainder of the
increase related to the issuance of common
shares under the Corporation's share
purchase, dividend reinvestment and stock
option plans, partially offset by an
increase in accumulated other comprehensive
loss.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the three and six months ended June 30, 2009, as compared to the same
periods in 2008, followed by a discussion of the nature of the variances in cash
flows.
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Fortis Inc.
Summary of Cash Flows (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
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Cash, beginning of period 94 67 27 66 58 8
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Cash provided by (used in)
-------------------------------------------------------------------------
Operating activities 275 232 43 504 425 79
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Investing activities (272) (203) (69) (482) (351) (131)
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Financing activities 41 (37) 78 50 (73) 123
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Foreign currency impact
on cash balances (1) - (1) (1) - (1)
-------------------------------------------------------------------------
Cash, end of period 137 59 78 137 59 78
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $43 million higher quarter over quarter and $79 million
higher year to date compared to the same period last year. The increases were
driven by higher earnings and favourable working capital changes at
FortisAlberta and the Terasen Gas companies.
Investing Activities: Cash used in investing activities was $69 million higher
quarter over quarter, driven by higher gross capital expenditures partially
offset by lower contributions in aid of construction at FortisAlberta. Cash
used in investing activities was $131 million higher year to date compared to
the same period last year. During the first quarter of 2008, TGI received
approximately $14 million in proceeds associated with the sale of surplus land.
Excluding the impact of the sale of surplus land in 2008, cash used in investing
activities was $117 million higher year to date compared to the same period last
year, driven by higher gross capital expenditures.
Gross capital expenditures were $277 million for the second quarter of 2009, $55
million higher than for the same quarter last year, and were $496 million year
to date, $100 million higher than for the same period last year. The increases
were driven by higher utility capital asset spending at FortisAlberta, the
Terasen Gas companies and the regulated electric utilities in the Caribbean.
Financing Activities: Cash provided by financing activities was $41 million for
the quarter compared to cash used in financing activities of $37 million for the
second quarter of 2008. The increase in cash from financing activities was
driven by lower net repayments of short-term borrowings, lower repayments of
long-term debt and higher net borrowings under committed credit facilities,
partially offset by lower proceeds from long-term debt and lower proceeds from
preference share issues.
Cash provided by financing activities was $50 million year to date compared to
cash used in financing activities of $73 million during the same period last
year. The increase in cash from financing activities was mainly due to lower
repayments of long-term debt and higher net borrowings under committed credit
facilities, partially offset by higher net repayments of short-term borrowings,
lower proceeds from long-term debt and lower proceeds from preference share
issues.
Net repayments of short-term borrowings were $89 million for the second quarter
of 2009, or $74 million lower than for the same quarter last year. The decrease
was driven by Maritime Electric and the Terasen Gas companies. Net repayments
of short-term borrowings were $239 million year to date, or $43 million higher
than for the same period last year. The increase was driven by the Terasen Gas
companies, partially offset by lower net repayments of short-term borrowings by
Maritime Electric.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease obligations and net borrowings (repayments) under committed
credit facilities for the quarter and year to date compared to the same periods
last year are summarized in the following tables.
--------------------------------------------------------------------------
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Fortis Inc.
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30
--------------------------------------------------------------------------
Quarter Year-to-date
--------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
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Terasen Gas companies - 247(1) (247) 99(2) 496(1)(3) (397)
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FortisAlberta - 99(4) (99) 99(5) 99(4) -
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FortisBC 104(6) - 104 104(6) - 104
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Newfoundland Power 65(7) - 65 65(7) - 65
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Maritime Electric - 60(8) (60) - 60(8) (60)
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Caribbean Utilities 34(9) - 34 34(9) - 34
--------------------------------------------------------------------------
Other - 3 (3) - 4 (4)
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Total 203 409 (206) 401 659 (258)
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(1) Issued May 2008, 30-year $250 million 5.80% unsecured debentures by
TGI. The net proceeds were primarily used to repay maturing $188
million 6.20% debentures and short-term borrowings.
(2) Issued February 2009, 30-year $100 million 6.55% unsecured debentures
by TGI. The net proceeds were used to repay credit facility borrowings
and to repay $60 million of 10.75% unsecured debentures that matured in
June 2009.
(3) Issued February 2008, 30-year $250 million 6.05% unsecured debentures
by TGVI. The net proceeds were used to repay committed credit facility
borrowings.
(4) Issued April 2008, 30-year $100 million 5.85% unsecured debentures.
The net proceeds were used to repay committed credit facility
borrowings.
(5) Issued February 2009, 30-year $100 million 7.06% unsecured debentures.
The net proceeds were used to repay committed credit facility
borrowings and for general corporate purposes.
(6) Issued June 2009, 30-year $105 million 6.10% unsecured debentures. The
net proceeds were used to repay committed credit facility borrowings,
for general corporate purposes, including financing capital
expenditures and working capital requirements, and help repay $50
million of 6.75% debentures that matured on July 31, 2009.
(7) Issued May 2009, 30-year $65 million 6.606% first mortgage sinking fund
bonds. The net proceeds were used to repay committed credit facility
borrowings and for general corporate purposes, including financing
capital expenditures.
(8) Issued April 2008, 30-year $60 million 6.05% secured first mortgage
bonds. The proceeds were used to repay short-term borrowings.
(9) Issued May 2009, 15-year US$30 million 7.50% unsecured notes. The net
proceeds were used to repay short-term borrowings and finance capital
expenditures.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Terasen Gas companies (63) (194) 131 (63) (194) 131
-------------------------------------------------------------------------
Caribbean Utilities (16) - (16) (16) - (16)
-------------------------------------------------------------------------
Fortis Properties (3) (3) - (5) (6) 1
-------------------------------------------------------------------------
Other (3) (3) - (7) (5) (2)
-------------------------------------------------------------------------
Total (85) (200) 115 (91) (205) 114
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended June 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2009 2008 Variance 2009 2008 Variance
-------------------------------------------------------------------------
Terasen Gas companies - 4 (4) - (261) 261
-------------------------------------------------------------------------
FortisAlberta 55 (74) 129 1 (2) 3
-------------------------------------------------------------------------
FortisBC (36) 8 (44) (31) 8 (39)
-------------------------------------------------------------------------
Newfoundland Power (57) (34) (23) (27) (14) (13)
-------------------------------------------------------------------------
Corporate 90 (170) 260 114 (208) 322
-------------------------------------------------------------------------
Total 52 (266) 318 57 (477) 534
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Borrowings under credit facilities by the utilities are primarily in support of
their respective capital expenditure programs and/or for working capital
requirements. Repayments are primarily financed through the issuance of
long-term debt, cash from operations and/or equity injections from Fortis. From
time to time, proceeds from preference share, common share and long-term debt
issues are used to repay borrowings under the Corporation's committed credit
facility. During the second quarter of last year, a net repayment of $170
million under the Corporation's committed credit facility was financed with
partial proceeds from the issuance of $230 million preference shares ($223
million net of costs). Some of the remaining proceeds from the preference share
offering were lent to Newfoundland Power, on a short-term basis, to repay
certain committed credit facility borrowings and the remaining proceeds were
used for other general corporate purposes.
Proceeds from the issuance of common shares increased $6 million quarter over
quarter and $13 million year to date compared to the same period last year,
reflecting the impact, effective March 1, 2009, of the Corporation's Amended and
Restated Dividend Reinvestment and Share Purchase Plan (the "Plan"). The Plan
provides participating common shareholders a 2 per cent discount on the purchase
of common shares, issued from treasury, with reinvested dividends.
Common share dividends were $44 million for the second quarter of 2009, up $4
million from the same quarter last year and were $88 million year to date, up $9
million from the same period last year. The increases were primarily due to an
increase in the number of common shares outstanding, primarily as a result of
the public issuance of 11.7 million common shares in December 2008 and a higher
dividend declared per common share compared to the same periods last year. The
dividend declared per common share in each of the first and second quarters of
2009 was $0.26, while the dividend declared per common share in each of the
first and second quarters of 2008 was $0.25.
Preference share dividends increased $2 million quarter over quarter and
increased $5 million year to date compared to the same period last year, as a
result of the dividends associated with the 9.2 million First Preference Shares,
Series G that were issued during the second quarter of 2008.
Contractual Obligations: Consolidated contractual obligations of Fortis over the
next five years and for periods thereafter, as of June 30, 2009, are outlined in
the following table. A detailed description of the nature of the obligations is
provided below and in the MD&A for the year ended December 31, 2008.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Contractual Obligations (Unaudited)
As at June 30, 2009
-------------------------------------------------------------------------
Due Due in Due in Due
within years 2 years 4 after
($ millions) Total 1 year and 3 and 5 5 years
-------------------------------------------------------------------------
Long-term debt 5,393 183 335 302 4,573
-------------------------------------------------------------------------
Brilliant Terminal Station 62 3 5 5 49
-------------------------------------------------------------------------
Gas purchase contract
obligations (based on
index prices as at June
30, 2009) 261 220 41 - -
-------------------------------------------------------------------------
Power purchase
obligations
FortisBC 2,810 39 77 76 2,618
FortisOntario 533 45 94 99 295
Maritime Electric (1) 127 85 24 2 16
Belize Electricity (2) 273 16 29 33 195
-------------------------------------------------------------------------
Capital cost 396 17 41 41 297
-------------------------------------------------------------------------
Joint-use asset and shared
service agreements 62 2 7 6 47
-------------------------------------------------------------------------
Office lease - FortisBC 19 1 3 3 12
-------------------------------------------------------------------------
Operating lease obligations 158 18 33 28 79
-------------------------------------------------------------------------
Equipment purchase commitment
- Caribbean Utilities 11 11 - - -
-------------------------------------------------------------------------
Equipment purchase commitment
- Fortis Turks & Caicos (3) 13 1 12 - -
-------------------------------------------------------------------------
Other 19 4 8 6 1
-------------------------------------------------------------------------
Total 10,137 645 709 601 8,182
-------------------------------------------------------------------------
(1) Reflects the impact of the extension to December 2010 of the take-or-
pay contract with New Brunswick Power ("NB Power") that previously
expired on March 31, 2009. The contract includes replacement energy
and capacity for the NB Power Point Lepreau Nuclear Generating Station
during its refurbishment outage.
(2) Includes a new 15-year power purchase agreement with Belize Aquaculture
Limited ("BAL"). The agreement provides for the supply of up to 15 MW
of capacity by BAL and expires in April 2024.
(3) Fortis Turks and Caicos has entered into an agreement with a supplier
to purchase two diesel-generating engines with a combined capacity of
approximately 17.5 MW for approximately US$12 million (CDN$13 million)
for delivery in April 2010 and January 2011.
Other Contractual Obligations:
In prior years, TGVI received non-interest bearing repayable loans from the
federal and provincial governments of $50 million and $25 million,
respectively, in connection with the construction and operation of the
Vancouver Island natural gas pipeline. As approved by the BCUC, these loans
have been recorded as government grants and have reduced the amounts
reported for utility capital assets. The government loans are repayable in
any fiscal year prior to 2012 under certain circumstances and subject to
the ability of TGVI to obtain non-government subordinated debt financing on
reasonable commercial terms. As the loans are repaid and replaced with
non-government loans, utility capital assets and long-term debt will
increase in accordance with TGVI's approved capital structure, as will
TGVI's rate base, which is used in determining customer rates. The
repayment criteria were met in 2008 and TGVI made an $8 million repayment
during the second quarter of 2009. As at June 30, 2009, the outstanding
balance of the repayable government loans was approximately $53 million.
Repayments of the government loans beyond 2009 are not included in the
contractual obligations table above as the amount and timing of the
repayments are dependent upon annual BCUC approval of the recovery of
TGVI's revenue deficiency deferral account and the ability of TGVI to
replace the government loans with non-government subordinated debt
financing on reasonable commercial terms.
Caribbean Utilities has a primary fuel supply contract with a major
supplier and is committed to purchase 80 per cent of the Company's fuel
requirements from this supplier for the operation of Caribbean Utilities'
diesel-fired generating plant. The contract is for three years terminating
in April 2010. The remaining approximate quantities, in millions of
imperial gallons, per the contract, on an annual basis by fiscal year are
27 in 2009 and 9 in 2010. The contract contains an automatic renewal
clause for the years 2010 through to 2012. Should any party choose to
terminate the contract within that two-year period, notice must be given a
minimum of one year in advance of the desired termination date.
Fortis Turks and Caicos has a renewable contract with a major supplier for
all of its diesel fuel requirements associated with the generation of
electricity. The approximate fuel requirements under this contract are 12
million imperial gallons per annum.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Based on the latest completed actuarial valuations, the Corporation's
consolidated defined benefit pension plan funding contributions, including
current service, solvency and special funding amounts, are expected to total
approximately $22 million for 2009, $18 million for 2010, $6 million for 2011,
$3 million for 2012 and $2 million for 2013. These pension funding amounts
include additional obligations determined under December 31, 2008 actuarial
valuations, completed in the first quarter of 2009, associated with defined
benefit pension plans at Newfoundland Power and the Corporation, and under a
December 31, 2007 actuarial valuation of a defined benefit pension plan at
Terasen, also completed in the first quarter of 2009.
Pension funding obligations for 2010 and beyond may increase pending completion
of the next actuarial valuations required as at December 31, 2009 and December
31, 2010 related to the defined benefit pension plans of the larger
subsidiaries.
Capital Structure: The Corporation's principal businesses of regulated gas and
electricity distribution require ongoing access to capital to allow the
utilities to fund the maintenance and expansion of infrastructure. Fortis
raises debt at the subsidiary level in support of infrastructure investment to
ensure regulatory transparency, tax efficiency and financing flexibility. To
help ensure access to capital, the Corporation targets a consolidated long-term
capital structure containing approximately 40 per cent equity, including
preference shares, and 60 per cent debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in the
utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Capital Structure (Unaudited)
As at
-------------------------------------------------------------------------
June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,426 58.9 5,468 59.5
-------------------------------------------------------------------------
Preference shares (2) 667 7.2 667 7.3
-------------------------------------------------------------------------
Common shareholders' equity 3,120 33.9 3,046 33.2
-------------------------------------------------------------------------
Total 9,213 100.0 9,181 100.0
-------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities
and equity
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The change in the capital structure was driven by net earnings applicable to
common shares, net of common share dividends, of $57 million during the first
half of 2009, combined with higher cash balances largely associated with the
issuance of long-term debt at FortisBC, the partial proceeds from which were
used to help repay debt that matured subsequent to the quarter end.
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt
credit rating)
DBRS BBB(high) (unsecured debt credit rating)
The credit ratings reflect the diversity of the operations of Fortis, the
stand-alone nature and financial separation of each of the regulated
subsidiaries of Fortis, management's commitment to maintaining low levels of
debt at the holding company level and the continued focus of Fortis on pursuing
the acquisition of stable regulated utilities.
Capital Program: The Corporation's principal businesses of regulated gas and
electricity distribution are capital intensive. 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.
During the first half of 2009, gross consolidated capital expenditures were $496
million. A breakdown of gross capital expenditures by segment for the first
half of 2009 is provided in the following table.
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Fortis Inc.
Gross Capital Expenditures (Unaudited) (1)
Year-to-date June 30, 2009
($ millions)
---------------------------------------------------------------------------
Other
Regula- Total
Tera- ted Regula- Regula-
sen New- Utili- ted ted Non-
Gas Fortis found- ties Utili- Utili- Regula-
Compa- Alberta Fortis- land Cana- ties - ties ted- Fortis
nies (2) BC Power dian Cana- Carib- Utility Proper-
(2) (3) (2) (2) (2) dian bean (4) ties Total
---------------------------------------------------------------------------
114 206 49 32 23 424 50 12 10 496
---------------------------------------------------------------------------
(1) Relates to utility capital assets, income producing properties and
intangible assets and includes expenditures associated with assets
under construction
(2) Includes asset removal and site restoration expenditures, net of
salvage proceeds, which are permissible in rate base
(3) Includes payments made to the AESO for investment in transmission
capital projects
(4) Includes non-regulated generation, non-regulated gas utility and
Corporate capital expenditures
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross consolidated capital expenditures for 2009 are expected to be more than $1
billion, approximately $50 million higher than that disclosed in the MD&A for
the year ended December 31, 2008. Planned capital expenditures are based on
detailed forecasts of energy demand, weather and cost of labour and materials,
as well as other factors, including economic conditions, which could change and
cause actual expenditures to differ from forecasts. The expected increase is
driven by FortisAlberta associated with higher anticipated customer driven
capital expenditures, including new customer connections, and the inclusion of
AESO transmission capital expenditures in total capital expenditures. The
increase is partially offset by lower spending at FortisBC associated with the
Okanagan Transmission Reinforcement Project, as discussed below, and the timing
of other capital projects.
Changes in the overall expected level, nature and timing of major capital
projects from those disclosed in the MD&A for the year ended December 31, 2008,
are discussed below.
FortisAlberta has revised its forecasted capital expenditures related to the
replacement of conventional meters with new Automated Meter Infrastructure
("AMI") technology. In response to the direction of the Alberta Department of
Energy on AMI capabilities, FortisAlberta has adjusted the scope of its planned
AMI program, which has contributed to an increase in the expected overall cost
of the project to $168 million from the $124 million disclosed in the MD&A for
the year ended December 31, 2008.
TGVI's construction of the 50-kilometer Squamish-to-Whistler natural gas
pipeline lateral was completed during spring 2009 and conversion of customer
appliances is expected to be completed during August 2009.
In June 2009, TGI applied to the BCUC to change its customer care delivery model
from an outsourced arrangement to an in-house customer care department,
including company-owned call centres and a new customer information system. If
approved, the new model would be in place effective January 2012 at a total
expected capital cost of approximately $145 million.
FortisBC will begin construction on the Okanagan Transmission Reinforcement
Project in August 2009 with completion expected in 2011. The total cost of the
project is currently forecasted at approximately $110 million, down from the
original estimate of $141 million as disclosed in the MD&A for the year ended
December 31, 2008. The decrease in cost is mainly due to lower forecasted
labour, equipment and commodity costs. The project relates to upgrading the
existing overhead transmission lines from 161 kilovolts ("kV") to 230 kV between
Penticton and Oliver and building a new 230-kV terminal in the Oliver area.
Over the five-year period 2009 through 2013, consolidated gross capital
expenditures are expected to total approximately $5 billion. Approximately 70
per cent of the capital spending is expected to be incurred at the Regulated
Electric Utilities, driven by FortisAlberta, FortisBC and the Corporation's
regulated utility operations in the Caribbean. Approximately 25 per cent is
expected to be incurred at the Regulated Gas Utilities and the remaining 5 per
cent is expected to relate to non-regulated activities. Capital expenditures at
the Regulated Utilities are subject to regulatory approval.
Cash Flow Requirements: At the operating 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 issues.
The Corporation's ability to service its debt obligations and pay dividends on
its common and preference shares is dependent on the financial results of the
operating subsidiaries and the related cash payments from these subsidiaries.
Certain regulated subsidiaries may be subject to restrictions which may limit
their ability to distribute cash to Fortis. Cash required of Fortis to support
subsidiary capital expenditure programs and finance acquisitions is expected to
be derived from a combination of borrowings under the Corporation's committed
credit facility and proceeds from the issuance of common shares, preference
shares and long-term debt. Depending on the timing of cash payments from the
subsidiaries, borrowings under the Corporation's committed credit facility may
be required from time to time to support the servicing of debt and payment of
dividends.
Management expects consolidated long-term debt maturities and repayments to
average approximately $170 million annually over the next five years. The
combination of available credit facilities and low annual debt maturities and
repayments provide the Corporation and its subsidiaries with flexibility in the
timing of access to capital markets.
Fortis and its subsidiaries, except for Belize Electricity and the Exploits
Partnership, as described below, were in compliance with debt covenants as at
June 30, 2009 and are expected to remain compliant throughout the remainder of
2009.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009
Rate Application, Belize Electricity does not meet certain debt covenant
financial ratios related to loans totalling $8 million (BZ$14 million), as at
June 30, 2009, with the International Bank for Reconstruction and Development
and the Caribbean Development Bank. The Company has informed the lenders of the
defaults and has requested appropriate waivers.
As the hydroelectric assets and water rights of the Exploits Partnership had
been provided as security for the Exploits Partnership's term loan, the recent
expropriation of such assets and rights by the Government of Newfoundland and
Labrador constituted an event of default under the loan. The loan is without
recourse to Fortis and was approximately $60 million as at June 30, 2009. The
lenders of the term loan have not demanded accelerated repayment. For further
information, see the "Critical Accounting Estimates - Contingencies" section of
this MD&A.
As at June 30, 2009, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.2 billion, of which approximately $1.6
billion was unused, including $456 million unused under the Corporation's $600
million committed revolving credit facility. The credit facilities are
syndicated almost entirely with the seven largest Canadian banks, with no one
bank holding more than 25 per cent of these facilities. Approximately $2.0
billion of the total credit facilities are committed facilities, the majority of
which have maturities between 2011 and 2013.
The following table summarizes the credit facilities of the Corporation and its
subsidiaries.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Credit Facilities (Unaudited)
--------------------------------------------------------------------------
Corporate Total as at Total as at
and Regulated Fortis June 30, December
($ millions) Other Utilities Properties 2009 31, 2008
--------------------------------------------------------------------------
Total credit
facilities 645 1,501 13 2,159 2,228
--------------------------------------------------------------------------
Credit facilities
utilized:
--------------------------------------------------------------------------
Short-term
borrowings - (170) - (170) (410)
--------------------------------------------------------------------------
Long-term debt (144) (128) - (272) (224)
--------------------------------------------------------------------------
Letters of credit
outstanding (1) (119) (1) (121) (104)
--------------------------------------------------------------------------
Credit facilities
available 500 1,084 12 1,596 1,490
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at June 30, 2009 and December 31, 2008, certain borrowings under the
Corporation's and subsidiaries' credit facilities have been 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.
Corporate and Other
In May 2009, Terasen entered into a $30 million committed revolving credit
facility maturing in May 2011 to replace its $100 million committed revolving
credit facility that matured in May 2009. The terms of the new credit facility
are substantially the same as those of the credit facility it replaced.
Regulated Utilities
On April 30, 2009, FortisBC amended its $150 million unsecured committed
revolving credit facility, including extending the maturity date of the $50
million portion of the facility to May 2012 from May 2011 and extending the
maturity date of the $100 million portion of the facility to May 2010 from May
2009.
In March 2009, Maritime Electric renegotiated its $50 million demand credit
facility and had it converted into a 364-day revolving committed credit
facility.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current
liabilities, other assets and deferred credits in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or nature of these instruments. The
fair value of long-term debt is calculated by using quoted market prices when
available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a market credit risk
premium equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt prior to maturity, the
fair value estimate does not represent an actual liability and, therefore, does
not include exchange or settlement costs. The fair value of the Corporation's
preference shares is determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt
and preference shares were as follows.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at June 30, 2009 As at December 31, 2008
--------------------------------------------------------------------------
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Long-term debt, including
current portion (1) 5,393 5,649 5,122 5,040
--------------------------------------------------------------------------
Preference shares, classified
as debt (2) 320 334 320 329
--------------------------------------------------------------------------
(1) Carrying value as at June 30, 2009 excludes unamortized deferred
financing costs of $37 million (December 31, 2008 - $34 million).
(2) Preference shares classified as equity do not meet the definition of a
financial instrument; however, the estimated fair value of the
Corporation's $347 million preference shares classified as equity was
$336 million as at June 30, 2009 (December 31, 2008: carrying value
$347 million; fair value $268 million).
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Risk Management: The Corporation's earnings from, and net investment in,
self-sustaining foreign subsidiaries are exposed to fluctuations in the US
dollar-to-Canadian dollar exchange rate. The Corporation has effectively
decreased the above exposure through the use of US dollar borrowings at the
corporate level. 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 or a currency pegged to the US dollar.
Belize Electricity's reporting currency is the Belizean dollar, while the
reporting currency of Caribbean Utilities, FortisUS Energy Corporation, BECOL,
and Fortis Turks and Caicos is the US dollar. The Belizean dollar is pegged to
the US dollar at BZ$2.00 equals US$1.00. As at June 30, 2009, all of the
Corporation's corporately held US$407 million long-term debt had been designated
as a hedge of a portion of the Corporation's foreign net investments. Foreign
currency exchange rate fluctuations associated with the translation of the
Corporation's corporately held US dollar borrowings designated as hedges are
recorded in other comprehensive income and serve to help offset unrealized
foreign currency gains and losses on the foreign net investments, which are also
recorded in other comprehensive income. As at June 30, 2009, the Corporation
had approximately US$130 million in foreign net investments remaining to be
hedged.
The Corporation and its subsidiaries also hedge exposures to fluctuations in
interest rates, foreign exchange rates and natural gas prices through the use of
derivative financial instruments. The Corporation and its subsidiaries do not
hold or issue derivative financial instruments for trading purposes.
The following table summarizes the valuation of the Corporation's consolidated
derivative financial instruments.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Derivative Financial Instruments (Unaudited)
--------------------------------------------------------------------------
As at June 30, As at December 31,
2009 2008
--------------------------------------------------------------------------
Estimated Estimated
Term to Number Carrying Fair Carrying Fair
Asset maturity of Value ($ Value ($ Value ($ Value ($
(Liability) (years) Contracts millions) millions) millions) millions)
--------------------------------------------------------------------------
Interest rate less
swaps than 2 2 - - - -
--------------------------------------------------------------------------
Foreign
exchange
forward approx.
contract 2 1 4 4 7 7
--------------------------------------------------------------------------
Natural gas
derivatives:
--------------------------------------------------------------------------
Swaps and Up to
options 5.25 223 (162) (162) (84) (84)
--------------------------------------------------------------------------
Gas purchase
contract Up to
premiums 2.25 51 (6) (6) (8) (8)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The interest rate swaps are held by Fortis Properties and are designated as
hedges of the cash flow risk related to floating-rate long-term debt and mature
in July 2009 and October 2010. The effective portion of changes in the fair
value of the interest rate swaps at Fortis Properties is recorded in other
comprehensive income.
The foreign exchange forward contract is held by TGVI and is designated as a
hedge of the cash flow risk related to approximately US$55 million required to
be paid under a contract for the construction of an LNG storage facility.
The natural gas derivatives are held by the Terasen Gas companies and are used
to fix the effective purchase price of natural gas as the majority of the
natural gas supply contracts have floating, rather than fixed, prices. The
price risk-management strategy of the Terasen Gas companies aims to improve the
likelihood that natural gas prices remain competitive with electricity rates,
temper gas price volatility on customer rates and reduce the risk of regional
price discrepancies.
The changes in the fair values of the foreign exchange forward contract and
natural gas derivatives are deferred as a regulatory asset or liability, subject
to regulatory approval, for recovery from, or refund to, customers in future
rates. The fair value of the foreign exchange forward contract was recorded in
accounts receivable as at June 30, 2009 and as at December 31, 2008. The fair
value of the natural gas derivatives of $168 million was recorded in accounts
payable as at June 30, 2009 (December 31, 2008 - accounts payable $92 million).
The interest rate swaps are valued at the present value of future cash flows
based on published forward future interest rate curves. The foreign exchange
forward contract is valued using the present value of future cash flows based on
published forward future foreign exchange market rate curves. The fair values
of the natural gas derivatives reflect the estimated amounts, based on published
forward curves, the Terasen Gas companies would have to receive or pay if forced
to settle all outstanding contracts at the balance sheet date.
The fair value of the Corporation's financial instruments, including
derivatives, reflects a point-in-time estimate 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 earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
As at June 30, 2009, 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
A detailed discussion of the Corporation's significant business risks is
provided in the MD&A for the year ended December 31, 2008. There were no
changes in the Corporation's significant business risks during the first half of
2009 from those disclosed in the MD&A for the year ended December 31, 2008,
except for those described below.
Labour Relations: The two collective agreements governing Newfoundland Power's
unionized employees represented by the International Brotherhood of Electrical
Workers, Local 1620, were ratified by the union in February and April 2009. The
collective agreements are effective October 1, 2008 and expire on September 30,
2011.
Transition to International Financial Reporting Standards ("IFRS"): In July
2009, the International Accounting Standards Board ("IASB") issued an Exposure
Draft on Rate-Regulated Activities stating that regulatory assets and
liabilities arising from activities subject to cost-of-service regulation may be
recognized under IFRS when certain conditions are met. The ability to record
regulatory assets and liabilities should reduce earnings' volatility at the
Corporation's regulated utilities that may have otherwise resulted under IFRS.
For further information, refer to the "Future Accounting Changes - Transition to
IFRS" section of this MD&A.
Impacts of Global Economic Downturn
The significant impacts of the global economic downturn on the Corporation are
provided below. The impacts are comparable with those disclosed in the MD&A for
the year ended December 31, 2008.
Capital Expenditures: Gross consolidated capital expenditures are expected to be
more than $1 billion for 2009 and total approximately $5 billion over the
five-year period from 2009 to 2013. Planned capital expenditures are based on
detailed forecasts of energy demand, weather and cost of labour and materials,
as well as other factors, including economic conditions, which could change and
cause actual expenditures to differ from forecasts. Significantly reduced
energy demand in the Corporation's service territories, as a result of a severe
and prolonged downturn in economic conditions, could reduce capital spending
which would, in turn, impact rate base and earnings' growth.
Cash Flows: The Corporation does not expect any significant decrease in
consolidated annual operating cash flows for 2009, as a result of the continued
downturn in the global economy in 2009. The subsidiaries expect to be able to
source the cash required to fund their 2009 capital expenditure programs.
Cost of and Access to Capital: The volatility in the global financial and
capital markets may increase the cost of, and affect the timing of issuance of,
long-term capital by the Corporation and its utilities in 2009. While the cost
of borrowing is expected to increase, as new long-term debt is expected to be
issued at higher rates due to an increase in credit spreads, the Corporation and
its utilities expect to continue to have reasonable access to capital in the
near to medium terms. Year to date, Fortis and its Canadian regulated utilities
raised $570 million in 30-year debt at rates ranging from 6.10% to 7.06% and
Caribbean Utilities raised 15-year US$40 million notes at 7.50%. The rates
obtained on these new long-term debt issues were, on average, approximately 100
to 150 basis points higher than those that would have been obtained during the
same period in 2008. The cost of renewed and extended credit facilities may
also increase going forward; however, any increased interest expense and/or fees
are not expected to have a material financial impact on the Corporation and its
utilities in 2009, as the majority of the total committed credit facilities have
maturities between 2011 and 2013. Due to the regulated nature of the
Corporation's utilities, increased borrowing costs are eligible to be recovered
in future customer rates.
Regulated Allowed Returns: The ROE adjustment mechanisms tied to long-term
Canada bond yields utilized at the Terasen Gas companies, FortisAlberta,
FortisBC and Newfoundland Power have resulted in low allowed ROEs. To address
this matter, the Terasen Gas companies filed an application with the BCUC
requesting a review of the current generic allowed ROE adjustment mechanism and
the deemed equity component of the capital structure for TGI. The application
contemplates an increase in TGI's allowed ROE to 11 per cent from 8.47 per cent,
effective July 1, 2009, and an increase in the allowed common equity component
of its capital structure to 40 per cent from 35 per cent, effective January 1,
2010. No change was requested in the risk-premium spread of 70 basis points
over TGI's allowed ROE in determining TGVI's allowed ROE. In May 2009,
Newfoundland Power requested an increase in its allowed ROE from 8.95 per cent
to 11 per cent, in conjunction with its 2010 customer rate application, to
reflect an increase in its cost of capital. Other Canadian regulators are also
starting to review cost of capital and related ROE adjustment mechanisms in
light of current financial market conditions. FortisAlberta is currently
engaged in a Generic Cost of Capital Proceeding with its regulator, which is
reviewing 2009 ROE calculations and capital structure levels for gas, electric
and pipeline utilities in Alberta that are regulated by the AUC. The National
Energy Board ("NEB") is also undertaking a review of cost of capital and ROE
levels and recently issued a decision increasing the regulated total cost of
capital of Trans Quebec & Maritimes Inc. ("TQM"), a Canadian regulated natural
gas pipeline utility, which translated into an approximate 100 basis points
increase in TQM's allowed ROE for 2008. The increase in the total cost of
capital and allowed ROE was the result of a change in methodology which now
takes into account financial market information which considers, among other
things, changes that have impacted financial markets and economic conditions.
The NEB is an independent federal agency that regulates several parts of
Canada's energy industry. In September 2009, the OEB is scheduled to hold a
stakeholder conference to review the cost of capital policy for future years as
it relates to utilities it regulates in Ontario.
Results of Operations: Achieving organic revenue and earnings' growth at Fortis
Properties' Hospitality Division may prove challenging in 2009 as a result of
the continued downturn in the global economy and its impact on leisure and
business travel and hotel stays. In the Caribbean, the level of, and
fluctuations in, tourism and related activities, which are closely tied to
economic conditions, influences electricity sales as it impacts electricity
demand of the large hotels and condominium complexes that are serviced by the
Corporation's regulated utilities in that region. As a result, electricity
sales growth at Regulated Caribbean Electric Utilities in 2009 is anticipated to
be approximately 2 per cent, down from 3 per cent as disclosed in the MD&A for
the first quarter of 2009, and down from 4 per cent as disclosed in the MD&A for
the year ended December 31, 2008. Electricity sales growth was approximately 6
per cent for 2008.
Higher energy prices can result in reduced consumption by residential customers.
Natural gas and crude oil exploration and production activities in certain of
the Corporation's service territories are closely correlated with natural gas
and crude oil prices. The level of these activities can influence energy
demand, affecting local energy sales in some of the Corporation's service
territories.
Defined Benefit Pension Plans: The fair value of the Corporation's consolidated
defined benefit pension plan assets decreased approximately 14 per cent during
2008, mainly due to unfavourable market conditions. Market-driven changes
impacting the performance of pension plan assets and the discount rates may
result in material changes in future pension funding requirements and pension
expense. The decline in fair value of the pension plan assets is expected to
have the impact of increasing the Corporation's consolidated defined benefit
pension plan funding obligations. The full impact of the decrease in the fair
value of the pension plan assets on future funding obligations is not
determinable until completion of the next actuarial valuations. With the
exception of the defined benefit pension plans at Newfoundland Power and the
Corporation and one of the defined benefit pension plans at Terasen, the next
scheduled actuarial valuations for funding purposes for defined benefit pension
plans of the larger subsidiaries are December 31, 2009 and December 31, 2010.
Including the impact of actuarial valuations completed during the first quarter
of 2009 for defined benefit pension plans at Newfoundland Power and the
Corporation and one of the defined benefit pension plans at Terasen,
consolidated pension funding contributions, including current service, solvency
and special funding amounts, are expected to increase from what was disclosed in
the MD&A for the year ended December 31, 2008 by the following amounts: 2009 -
$5 million, 2010 - $6 million, 2011 - $6 million, 2012 - $3 million, and 2013 -
$2 million. Fortis expects defined benefit pension plan funding requirements to
be sourced primarily from a combination of cash generated from operations and
amounts available for borrowing under existing credit facilities.
The discount rates used to determine defined benefit pension expense for 2009
have increased compared to rates used to determine defined benefit pension
expense for 2008, as a result of the impact of increased credit risk spreads on
investment-grade corporate bonds due to volatility in the capital markets.
Fortis expects no material increase in its consolidated pension expense for 2009
related to its defined benefit pension plans. The amortization of 2008 losses
associated with the pension plan assets is expected to be largely offset by the
impact of higher assumed discount rates. Consolidated defined benefit pension
plan expense for 2009 will not be materially impacted by the outcome of the
actuarial valuations completed for the defined benefit pension plans at
Newfoundland Power and the Corporation and one of the defined benefit pension
plans at Terasen during the first quarter of 2009.
Any increase in future pension funding requirements and/or pension expense at
the regulated utilities is expected to be recovered from, or refunded to,
customers in future rates, subject to forecast risk. At the Terasen Gas
companies and FortisBC, however, actual pension expense above or below the
forecast pension expense approved for recovery in customer rates for the year is
subject to deferral account treatment for recovery from, or refund to, customers
in future rates, subject to regulatory approval.
Counterparty Risk: The Terasen Gas companies are exposed to credit risk in the
event of non-performance by counterparties to derivative financial instruments.
The Terasen Gas companies are also exposed to significant credit risk on
physical off-system sales. The Terasen Gas companies deal with high
credit-quality institutions in accordance with established credit approval
practices. Due to recent events in the capital markets, including significant
government intervention in the banking system, the Terasen Gas companies have
further limited the financial counterparties they transact with and have reduced
available credit to, or taken additional security from, the physical off-system
sales counterparties with which they transact. To date, the Terasen Gas
companies have not experienced any counterparty defaults and they do not expect
any counterparties to fail to meet their obligations; however, the credit
quality of counterparties, as recent events have indicated, can change rapidly.
An extended decline in economic conditions could also impair the ability of
customers to pay for gas and electricity consumed, thereby affecting the aging
and collection of the utilities' trade receivables.
Credit Ratings: Fortis and its regulated utilities do not anticipate any
material adverse rating actions by the credit rating agencies in the near term.
However, the current global financial crisis has placed increased scrutiny on
rating agencies and rating agency criteria which may result in changes to credit
rating practices and policies. Year to date, there were no changes in the credit
ratings for the Corporation and its currently rated subsidiaries except for
Newfoundland Power. In August 2009, Moody's upgraded the credit rating of
Newfoundland Power's first mortgage bonds two notches from Baa1 to A2. Moody's
also confirmed its existing credit ratings for TGI, FortisAlberta and FortisBC;
S&P confirmed its existing credit ratings for Maritime Electric and Caribbean
Utilities; and DBRS confirmed its existing credit ratings for FortisBC and TGI.
CHANGES IN ACCOUNTING STANDARDS
Rate-Regulated Operations: Effective January 1, 2009, the Canadian Accounting
Standards Board (the "AcSB") amended: (i) Canadian Institute of Chartered
Accountants ("CICA") Handbook Section 1100, Generally Accepted Accounting
Principles, removing the temporary exemption providing relief to entities
subject to rate regulation from the requirement to apply the Section to the
recognition and measurement of assets and liabilities arising from rate
regulation; and (ii) Section 3465, Income Taxes to require the recognition of
future income tax liabilities and assets, as well as offsetting regulatory
assets and liabilities, by entities subject to rate regulation.
Effective January 1, 2009, with the removal of the temporary exemption in
Section 1100, the Corporation must now apply Section 1100 to the recognition of
assets and liabilities arising from rate regulation. Certain assets and
liabilities arising from rate regulation continue to have specific guidance
under a primary source of Canadian GAAP that applies only to the particular
circumstances described therein, including those arising under Section 1600,
Consolidated Financial Statements, Section 3061, Property, Plant and Equipment,
Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and
Discontinued Operations. The assets and liabilities arising from rate
regulation, as described in Note 5 to the Corporation's interim unaudited
consolidated financial statements for the three and six months ended June 30,
2009 and Note 4 to the Corporation's 2008 annual audited consolidated financial
statements, do not have specific guidance under a primary source of Canadian
GAAP. Therefore, Section 1100 directs the Corporation to adopt accounting
policies that are developed through the exercise of professional judgment and
the application of concepts described in Section 1000, Financial Statement
Concepts. In developing these accounting policies, the Corporation may consult
other sources, including pronouncements issued by bodies authorized to issue
accounting standards in other jurisdictions. Therefore, in accordance with
Section 1100, the Corporation has determined that all of its regulatory assets
and liabilities qualify for recognition under Canadian GAAP and this recognition
is consistent with US Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation. Therefore, there was
no effect on the Corporation's consolidated financial statements, as at January
1, 2009, due to the removal of the temporary exemption from Section 1100.
Effective January 1, 2009, Fortis retroactively recognized future income tax
assets and liabilities and related regulatory liabilities and assets, without
prior period restatement, for the amount of future income taxes expected to be
refunded to, or recovered from, customers in future gas and electricity rates.
Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and
Newfoundland Power used the taxes payable method of accounting for income taxes.
The effect on the Corporation's consolidated financial statements, as at January
1, 2009, of adopting amended Section 3465, Income Taxes included an increase in
total future income tax liabilities and total future income tax assets of $491
million and $24 million, respectively; an increase in regulatory assets and
regulatory liabilities of $535 million and $59 million, respectively; and a
combined $9 million net increase in income taxes payable, deferred credits,
other assets, utility capital assets and goodwill associated with the
reclassification of future income taxes that were previously netted against
these respective balance sheet items. Included in the future income tax assets
and liabilities recorded are the future income tax effects of the subsequent
settlement of the related regulatory assets and liabilities through customer
rates.
Goodwill and Intangible Assets: Effective January 1, 2009, the Corporation
retroactively adopted the new CICA Handbook Section 3064, Goodwill and
Intangible Assets. This Section, which replaces Section 3062, Goodwill and
Other Intangible Assets and Section 3450, Research and Development Costs,
establishes standards for the recognition, measurement and disclosure of
goodwill and intangible assets. As at December 31, 2008, the impact of
retroactively adopting Section 3064 was a reclassification of $261 million to
intangible assets and related decreases of $259 million to utility capital
assets, $1 million to income producing properties and $1 million to other
assets, due to the reclassification of the net book value of land, transmission
and water rights, computer software costs, franchise costs, customer contracts
and other costs.
Credit Risk and the Fair Value of Financial Assets and Financial Liabilities:
During the first quarter of 2009, the Corporation adopted the new Emerging
Issues Committee Abstract ("EIC")-173, Credit Risk and the Fair Value of
Financial Assets and Financial Liabilities, which was issued on January 20,
2009. EIC-173 requires that the Corporation's own credit risk and the credit
risk of its counterparties be taken into account in determining the fair value
of a financial instrument. There was no material effect on the Corporation's
interim unaudited consolidated financial statements as a result of adopting
EIC-173.
FUTURE ACCOUNTING CHANGES
Transition to IFRS
In February 2008, the AcSB confirmed that the use of IFRS will be required in
2011 for publicly accountable enterprises in Canada. In March 2009, the AcSB
issued a second Omnibus Exposure Draft confirming that publicly accountable
enterprises in Canada will be required to apply IFRS, in full and without
modification, beginning January 1, 2011. The Corporation's expected IFRS
transition date of January 1, 2011 will require the restatement, for comparative
purposes, of amounts reported by the Corporation for the year ended December 31,
2010, and of amounts reported on the Corporation's opening IFRS balance sheet as
at January 1, 2010.
The Corporation is continuing to assess the financial reporting impacts of
adopting IFRS in 2011. The full impact on future financial position and results
of operations is not reasonably determinable or estimable at this time in light
of the recently released Exposure Draft on Rate-Regulated Activities. The
Corporation does anticipate a significant increase in disclosure resulting from
the adoption of IFRS and is identifying and assessing these additional
disclosure requirements, as well as systems changes that will be necessary to
compile the required disclosures.
IFRS Conversion Project: The Corporation commenced its IFRS Conversion Project
in 2007 and has established a formal project governance structure which includes
the audit committee, senior management and project teams from each of the Fortis
subsidiaries. Overall project governance, management and support are coordinated
by Fortis. An independent external advisor has also been engaged to assist in
the IFRS Conversion Project. Project progress reports are provided to the
Corporation's Audit Committee on a quarterly basis. The Corporation has also
engaged its external auditors, Ernst & Young, LLP, to review accounting policy
determinations as they are arrived at and agreed to internally by the
Corporation's project team.
The Corporation's IFRS Conversion Project consists of three phases: Scoping and
Diagnostics, Analysis and Development, and Implementation and Review.
Phase One: Scoping and Diagnostics, which involved project planning and staffing
and identification of differences between current Canadian GAAP and IFRS, was
completed in the first half of 2008. The areas of accounting difference of
highest potential impact to the Corporation, based on existing IFRS at the time,
were identified to include rate-regulated accounting; property, plant and
equipment; investment property; provisions and contingent liabilities; employee
benefits; impairment of assets; income taxes; business combinations; and initial
adoption of IFRS under the provisions of IFRS 1, First-Time Adoption of
International Financial Reporting Standards ("IFRS 1").
Phase Two: Analysis and Development is nearing completion and involves detailed
diagnostics and evaluation of the financial impacts of various options and
alternative methodologies provided for under IFRS; identification and design of
operational and financial business processes; initial staff training and audit
committee orientation; analysis of IFRS 1 optional exemptions and mandatory
exceptions to the general requirement for full retrospective application upon
transition; summarization of 2011 IFRS disclosure requirements; and development
of required solutions to address identified issues.
Phase Three: Implementation and Review, has recently commenced and involves the
execution of changes to information systems and business processes; completion
of formal authorization processes to approve recommended accounting policy
changes; and further training programs across the Corporation's finance and
other affected areas, as necessary. It will culminate in the collection of
financial information necessary to compile IFRS-compliant financial statements
and reconciliations; embedding of IFRS in business processes; and audit
committee approval of IFRS-compliant interim and annual financial statements for
2011.
Accounting for Rate-Regulated Activities under IFRS: IFRS does not currently
provide specific guidance with respect to accounting for rate-regulated
activities. However, in December 2008, the IASB initiated a project on
accounting for rate-regulated activities and whether or not rate-regulated
entities could or should recognize assets or liabilities as a result of
rate-regulation imposed by a regulatory body.
On July 23, 2009, the IASB issued an Exposure Draft on Rate-Regulated
Activities. Comments on the Exposure Draft are to be submitted for consideration
by the IASB by November 20, 2009. Based on the current project timeline of the
IASB, a final standard is expected to be issued in 2010.
Based on the Exposure Draft as it currently exists, regulatory assets and
liabilities arising from activities subject to cost-of-service regulation may be
recognized under IFRS when certain conditions are met. The ability to record
regulatory assets and liabilities, as proposed, should reduce the earnings'
volatility at the Corporation's regulated utilities that may have otherwise
resulted under IFRS, but will result in the requirement to provide enhanced
balance sheet presentation and note disclosures. However, uncertainty as to the
final outcome of this Exposure Draft, and the final standard on accounting for
rate-regulated activities under IFRS, has resulted in the Corporation being
unable to reasonably estimate and conclude on the impact on the Corporation's
future financial position and results of operations with respect to differences,
if any, in accounting for rate-regulated activities under IFRS versus Canadian
GAAP.
Differences between IFRS and Canadian GAAP, in addition to those referred to
below under "Accounting Policy Impacts and Decisions", may still be identified
based on further detailed analysis by the Corporation, the outcome of a final
standard on accounting for rate-regulated activities and other changes in IFRS
prior to the Corporation's conversion to IFRS in 2011.
Regulators in the jurisdictions in which the Corporation maintains regulated
utility operations have initiated, or are engaged in, consultative processes
aimed at addressing issues related to the transition to IFRS. These regulators
are also working to define regulatory accounting requirements and respective
changes that may be required subsequent to January 1, 2011.
During the second quarter of 2009, the AUC issued Rule 026 which provides both a
set of guiding principles and positions on the elements of IFRS that will be
adopted for rate-making purposes. FortisAlberta and other utilities in Alberta
regulated by the AUC collaborated closely with the AUC in the development of
Rule 026.
Also during the second quarter of 2009, TGI, along with the other regulated
companies in British Columbia, drafted a set of IFRS guidelines for use in
regulatory applications being submitted by the utilities to the BCUC. During
the same period, TGI and TGVI filed applications with the BCUC for the purpose
of setting customer rates for 2010 and 2011. As part of these applications, TGI
and TGVI have applied for changes in accounting policies that would, subject to
review by the external auditors, be compliant with IFRS where possible.
Accounting Policy Impacts and Decisions: The Corporation has completed an
initial assessment of the impacts of adopting IFRS based on the standards as
they currently exist, and identified the following as having the greatest
potential to impact the Corporation's accounting policies, financial reporting
and information systems requirements upon conversion to IFRS. However, final
conclusions cannot be reached at this time with respect to the Corporation's
rate-regulated entities pending further certainty as to a final IFRS standard on
accounting for rate-regulated activities.
(a) Property Plant and Equipment
IFRS and Canadian GAAP contain the same basic principles of accounting for
property, plant and equipment; however, differences in application do exist. For
example, capitalization of directly attributable costs in accordance with IAS
16, Property, Plant and Equipment ("IAS 16") may require measurement of an item
of property, plant and equipment upon initial recognition to include or exclude
certain previously recognized amounts under Canadian GAAP. Specifically, there
may be changes in accounting for:
i) the amount of capitalized overheads;
ii) the capitalization of major inspections that were previously
expensed under Canadian GAAP;
iii) the capitalization of depreciation for which the future economic
benefits of that asset are absorbed in the production of another
asset; and
iv) the capitalization of borrowing costs in accordance with IAS 23,
Borrowing Costs.
IAS 16 also requires an allocation of the amount initially recognized in respect
of an item of property, plant and equipment to its significant parts and the
depreciation of each such part separately. This method of componentizing
property, plant and equipment may result in an increase in the number of
component parts that are recorded and depreciated and, as a result, may impact
the calculation of depreciation expense.
Upon transition to IFRS, an entity has the elective option to reset the cost of
its property, plant and equipment based on fair value in accordance with the
provisions of IFRS 1, and to use either the cost model or the revaluation model
to measure its property, plant and equipment subsequent to transition.
Currently, the Corporation intends to reset the cost of hotel properties owned
by its non-regulated subsidiary, Fortis Properties, upon transition to IFRS on
January 1, 2010 based on fair value, and to use the cost model to measure all of
Fortis Properties' property, plant and equipment (excluding those assets to be
reclassified as investment property under IFRS, as referred to below) subsequent
to transition.
The final extent of the impact of applying IAS 16 by the Corporation's
rate-regulated utility subsidiaries, and elective options with respect to
accounting for their property, plant and equipment upon transition to IFRS,
cannot be made at this time pending further certainty as to a final standard on
accounting for rate-regulated activities.
(b) Investment Property
IAS 40, Investment Property ("IAS 40") defines investment property as land or
buildings held to earn rental income, for capital appreciation or both. The
Corporation's real estate assets, which are currently owned by its non-regulated
subsidiary, Fortis Properties, and recorded as property, plant and equipment
under Canadian GAAP, will be re-classified as investment property under IFRS.
The Corporation has the elective option to reset the cost of investment property
based on its fair value at the date of transition as of January 1, 2010. IAS 40
provides further options for measuring investment property subsequent to initial
recognition using either the cost model or the fair value model. Currently,
Fortis Properties intends to reset the cost of its investment property upon
transition to IFRS based on fair value as of January 1, 2010 and to use the fair
value model to measure its investment property subsequent to transition. Use of
the fair value model under IAS 40 means that the Corporation will not recognize
depreciation expense on its statement of earnings under IFRS with respect to its
investment properties, and that changes in the fair value of its investment
properties will be recognized in earnings each period.
(c) Provisions and Contingent Liabilities
IAS 37, Provisions, Contingent Liabilities and Contingent Assets ("IAS 37")
requires a provision to be recognized when: (i) there is a present obligation as
a result of a past transaction or event; (ii) it is probable that an outflow of
resources will be required to settle the obligation; and (iii) a reliable
estimate can be made of the obligation. Under Canadian GAAP, the criterion for
recognition is "likely", which is a higher threshold than "probable". It is
possible, therefore, that some contingent liabilities which would meet the
recognition criterion under IFRS would not have been recognized under Canadian
GAAP.
(d) Employee Benefits
IAS 19, Employee Benefits ("IAS 19") requires the past service cost element of
defined benefit plans to be expensed on an accelerated basis, with vested past
service costs being expensed immediately and unvested past service costs being
recognized on a straight-line basis until the benefits become vested. In
addition, actuarial gains and losses are permitted under IAS 19 to be recognized
directly in equity rather than through earnings, and IFRS 1 also provides an
option to recognize immediately in retained earnings all cumulative actuarial
gains and losses existing as at the date of transition to IFRS.
Under Canadian GAAP, past service costs are generally amortized on a
straight-line basis over the expected average remaining service period of active
employees in the defined benefit plan.
The Corporation and its subsidiaries maintain a number of defined benefit
pension plans and supplementary and other post-employment benefit plans which
will be subject to different accounting treatment under IFRS as compared to
Canadian GAAP. The full extent of the impact of applying IAS 19 cannot be made
at this time, pending further certainty as to a final standard on accounting for
rate-regulated activities.
(e) Impairment of Assets
IAS 36, Impairment of Assets ("IAS 36") uses a one-step approach for testing and
measuring asset impairments, with asset carrying values being compared to the
higher of value in use and fair value less costs to sell. Value in use is
defined as being equal to the present value of future cash flows expected to be
derived from the asset. In the absence of an active market, fair value less
costs to sell may also be determined using discounted cash flows. The use of
discounted cash flows under IFRS to test and measure asset impairment differs
from Canadian GAAP where undiscounted future cash flows are used to compare
against the asset's carrying value to determine if impairment exists. This may
result in more frequent write-downs in the carrying value of assets under IFRS
since asset carrying values that were previously supported under Canadian GAAP
based on undiscounted cash flows may not be supported on a discounted cash flow
basis under IFRS. However, under IAS 36, previous impairment losses may be
reversed where circumstances change such that the impairment has reduced. This
also differs from Canadian GAAP, which prohibits the reversal of previously
recognized impairment losses.
As the majority of the Corporation's assets are owned by utility subsidiaries
that are rate regulated, the potential for and extent of any impairment losses
will be primarily subject to the continued ability of the utilities to recover
costs through the regulatory process.
As stated above, the Corporation intends to reset the cost of investment
property owned by its non-regulated subsidiary, Fortis Properties, upon
transition to IFRS based on fair value as of January 1, 2010 and to use the fair
value model to measure its investment property subsequent to transition.
Changes in the fair value of the Corporation's investment property each period
will, therefore, be reflected under IFRS in the statement of earnings.
The Corporation's other non-regulated assets will be subject to the one-step
approach under IFRS for testing and measuring asset impairments which may result
in some impairments being recognized or reversed under IFRS that would not have
been required or permitted under Canadian GAAP.
(f) Income Taxes
IAS 12, Income Taxes ("IAS 12") prescribes that an entity account for the tax
consequences of transactions and other events in the same way that it accounts
for the transactions and other events themselves. Therefore, where transactions
and other events are recognized in earnings, the recognition of deferred tax
assets or liabilities which arise from those transactions should also be
recorded in earnings. For transactions that are recognized outside of the
statement of earnings, either in other comprehensive income or directly in
equity, any related tax effects should also be recognized outside of the
statement of earnings.
The most significant impact of IAS 12 on the Corporation will be derived
directly from the accounting policy decisions made under IAS 16 and IAS 40. In
addition, the Corporation's rate-regulated subsidiaries currently account for
income taxes based on regulatory decisions. Therefore, the impact on the
Corporation of accounting for the tax consequences of transactions and other
events under IFRS versus Canadian GAAP cannot be fully determined at this time
pending further certainty as to a final IFRS standard on accounting for
rate-regulated activities.
(g) Business Combinations
Under IFRS 3, Business Combinations ("IFRS 3"), business combinations must be
accounted for by applying the acquisition method. One of the parties to a
business combination can always be identified as the acquirer, being the entity
that obtains control of the other business. Control is defined as the power to
govern the financial and operating policies of an entity so as to obtain
benefits from its activities. Fortis, as an acquirer, shall identify the date on
which it obtains control of an acquiree. This date is usually the closing date
of the acquisition, which would generally be the date on which the Corporation
legally transfers the consideration or acquires the assets and assumes the
liabilities of the acquiree. As of the date on which it obtains control, Fortis
shall recognize, separately from goodwill, the identifiable assets acquired, the
liabilities assumed and any non-controlling interest in the acquiree in
accordance with IFRS 3.
In accordance with IFRS 3, acquisition-related costs incurred to effect a
business combination shall be expensed in the period the costs are incurred.
Under IFRS, these costs are not permitted to form a component of goodwill as is
permitted under Canadian GAAP.
Under IFRS 1, an entity has the option to retroactively apply IFRS 3 to all
business combinations or may elect to apply the standard prospectively only to
those business combinations that occur after the date of transition. The
Corporation currently intends to avail itself of the elective exemption under
IFRS 1 which removes the requirement to retrospectively restate all business
combinations prior to the date of transition to IFRS, subject to certain balance
sheet adjustments that may be required at FortisAlberta with respect to goodwill
and intangible assets that have been recorded previously under Canadian GAAP
using pushdown accounting. The above adjustments are not expected to have an
impact on the Corporation's consolidated financial position upon transition to
IFRS.
The AcSB recently issued new CICA Handbook Section 1582, Business Combinations
and Section 1602, Non-Controlling Interests. The effective date of these
sections is fiscal years beginning on or after January 1, 2011, however, early
adoption is permitted. These new Handbook sections are substantially aligned
with the accounting for business combinations and non-controlling interests
under IFRS 3.
(h) IFRS 1, First-Time Adoption of International Financial Reporting Standards
IFRS 1 provides the framework for the first time adoption of IFRS and specifies
that, in general, an entity shall apply the principles under IFRS
retrospectively. IFRS 1 also specifies that the adjustments that arise on
retrospective conversion to IFRS from other GAAP should be directly recognized
in retained earnings. Certain optional exemptions and mandatory exceptions to
retrospective application are provided for under IFRS 1.
The Corporation has completed an analysis of IFRS 1. While preliminary decisions
have been made with respect to the elective exemptions available upon
transition, final decisions cannot be made at this time pending further
certainty as to a final IFRS standard on accounting for rate-regulated
activities.
(i) Internal Controls over Financial Reporting and Disclosure
In accordance with the Corporation's approach to the certification of internal
controls required under Canadian Securities Administrators' National Instrument
52-109, all entity level, information technology, disclosure and business
process controls will require updating and testing to reflect changes arising
from the Corporation's conversion to IFRS. Where material changes are
identified, these changes will be mapped and tested to ensure that no material
deficiencies exist as a result of the Corporation's conversion to these new
accounting standards.
(j) Information Systems
It is anticipated that the adoption of IFRS will have an impact on information
systems requirements. The Corporation has assessed the need for systems upgrades
or modifications to ensure an efficient conversion to IFRS. As part of Phase Two
of the Corporation's IFRS Conversion Project, information systems' plans have
been prepared for implementation in Phase Three. The extent of the impact on the
Corporation's information systems is largely dependant upon the final IFRS
standard on accounting for rate-regulated activities and is, therefore, not
fully determinable at this time.
The IASB has a number of on-going projects on its agenda, in addition to the
project on accounting for rate-regulated activities, that may result in changes
to existing IFRS prior to the Corporation's conversion in 2011. The Corporation
continues to monitor these projects and the impact that any resulting IFRS
changes may have on its anticipated accounting policies, financial position or
results of operations under IFRS for 2011 and beyond.
Business Combinations
In January 2009, the AcSB issued new CICA Handbook Section 1582, Business
Combinations, together with Section 1601, Consolidated Financial Statements and
Section 1602, Non-Controlling Interests. These new accounting standards are
effective for fiscal years beginning on or after January 1, 2011. As a result of
adopting Section 1582, changes in the determination of the fair value of the
assets and liabilities of the acquiree will result in a different calculation of
goodwill. Such changes include the expensing of acquisition-related costs
incurred during a business acquisition, rather than recording them as a capital
transaction, and the disallowance of recording restructuring accruals by the
acquirer. Section 1582 will affect the recognition of business combinations
completed by the Corporation on or after January 1, 2011 and, as a result, may
have a material impact on the Corporation's consolidated earnings and financial
position.
Section 1601 establishes standards for the preparation of consolidated financial
statements. Section 1602 establishes standards for accounting for a
non-controlling interest in a subsidiary in consolidated financial statements
subsequent to a business combination. The adoption of Sections 1601 and 1602
will result in non-controlling interests being presented as components of
equity, rather than as liabilities, on the consolidated balance sheet.
Also, net earnings and components of other comprehensive income attributable to
the owners of the parent company and to the non-controlling interests are
required to be separately disclosed on the statement of earnings. The adoption
of Sections 1601 and 1602 is not expected to have a material impact on the
Corporation's consolidated earnings, cash flows or financial position.
Financial Instruments
In June 2009, the AcSB issued amendments to the CICA Handbook Section 3862,
Financial Instruments - Disclosures to include additional disclosure
requirements about the fair value measurement of financial instruments and to
enhance liquidity risk disclosures. The amendments are effective for annual
financial statements relating to fiscal years ending after September 30, 2009.
The Corporation will reflect the additional disclosures in its 2009 annual
audited consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial
statements in accordance with Canadian GAAP requires management to make
estimates and judgments that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the consolidated financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are based on
historical experience, current conditions and various other assumptions believed
to be reasonable under the circumstances. Additionally, certain estimates and
judgments are necessary since the regulatory environments in which the
Corporation's utilities operate often require amounts to be recorded at
estimated values until these amounts are finalized pursuant to regulatory
decisions or other regulatory proceedings. Due to changes in facts and
circumstances and the inherent uncertainty involved in making estimates, actual
results may differ significantly from current estimates. Estimates and
judgments are reviewed periodically and, as adjustments become necessary, are
reported in earnings in the period they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the six months ended June 30,
2009 from those disclosed in the Corporation's MD&A for the year ended December
31, 2008, except for those described below related to the accounting for income
taxes and contingencies.
Income Taxes: Income taxes are determined based on estimates of the
Corporation's current income taxes and estimates of future income taxes
resulting from temporary differences between the carrying values of assets and
liabilities in the consolidated financial statements and their tax values. The
use of estimation with respect to recording future income taxes has increased
due to the adoption by the Corporation of amended CICA Handbook Section 3465,
Income Taxes, effective January 1, 2009. A future income tax asset or liability
is determined for each temporary difference based on the future tax rates that
are expected to be in effect and management's assumptions regarding the expected
timing of the reversal of such temporary differences. Future income tax assets
are assessed for the likelihood that they will be recovered from future taxable
income. To the extent recovery is not considered more likely than not, a
valuation allowance is recorded and charged against earnings in the period that
the allowance is created or revised. Estimates of the provision for income
taxes, future income tax assets and liabilities, and any related valuation
allowance might vary from actual amounts incurred.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with ordinary course business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations. There were no material changes in the
Corporation's contingent liabilities during the six months ended June 30, 2009
from those disclosed in the MD&A for the year ended December 31, 2008, except as
disclosed below.
Exploits Partnership
The Exploits Partnership operated two non-regulated hydroelectric generation
plants in Newfoundland with a combined capacity of approximately 140 MW. The
Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent
by Abitibi. 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, a Crown corporation, as agent for the Government
of Newfoundland and Labrador. The loss of control over cash flows and operations
required Fortis to report its investment in the Exploits Partnership using the
equity method of accounting, effective February 13, 2009. Equity earnings
recognized in the first and second quarters of 2009 are equivalent to the
amounts that would have been recognized under normal hydrology in the absence of
the expropriation. Discussions between Fortis Properties and Nalcor Energy with
respect to expropriation matters are ongoing.
Terasen
On July 16, 2009, Terasen 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 a pipeline rupture in
July 2007. This claim is in its early stages and the amount and outcome of it is
indeterminable at this time.
QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended September 30, 2007 through June 30, 2009. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements which, in the opinion of management, have been
prepared in accordance with Canadian GAAP and as required by utility regulators.
The timing of the recognition of certain assets, liabilities, revenue and
expenses, as a result of regulation, may differ from that otherwise expected
using Canadian GAAP for non-regulated entities. The differences and nature of
regulation are disclosed in Notes 2 and 4 to the Corporation's 2008 annual
audited consolidated financial statements. The quarterly operating results are
not necessarily indicative of results for any future period and should not be
relied upon to predict future performance.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Summary of Quarterly Results (Unaudited)
--------------------------------------------------------------------------
Net Earnings
Applicable
to Common
Revenue Shares Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
--------------------------------------------------------------------------
June 30, 2009 754 53 0.31 0.31
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March 31, 2009 1,201 92 0.54 0.52
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December 31, 2008 1,182 76 0.48 0.46
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September 30, 2008 727 49 0.31 0.31
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June 30, 2008 848 29 0.19 0.18
--------------------------------------------------------------------------
March 31, 2008 1,146 91 0.58 0.55
--------------------------------------------------------------------------
December 31, 2007 1,018 79 0.51 0.49
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September 30, 2007 651 31 0.20 0.20
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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 impacted by the cost of
purchased power and the commodity cost of natural gas, which are flowed through
to customers without mark up. Given the diversified group of companies,
seasonality may vary. Most of the annual earnings of the Terasen Gas companies
are generated in the first and fourth quarters. Financial results for the second
quarter ended June 30, 2008 reflected the $13 million unfavourable impact to
Fortis of a charge recorded at Belize Electricity as a result of the June 2008
regulatory rate decision. Due to a shift in the quarterly distribution of annual
purchased power expense at Newfoundland Power, the utility's earnings in 2008
were lower in the first and fourth quarters and higher in the second and third
quarters compared to the same periods in 2007. Newfoundland Power's annual
earnings were not impacted by the shift in the quarterly distribution of annual
purchased power expense. Financial results from November 2008 were impacted by
the acquisition of the Sheraton Hotel Newfoundland and from April 2009 by the
acquisition of the Holiday Inn Select in Windsor, Ontario.
June 30, 2009/June 30, 2008 - Net earnings applicable to common shares were $53
million, or $0.31 per common share, for the second quarter of 2009 compared to
earnings of $29 million, or $0.19 per common share, for the second quarter of
2008. Results for the second quarter of 2008 included one-time charges of
approximately $15 million pertaining to Belize Electricity, associated with the
June 2008 regulatory rate decision, and FortisOntario, associated with the
repayment, during the second quarter of 2008, of an interconnection-agreement
related refund received in the fourth quarter of 2007. Excluding these one-time
charges, earnings increased $9 million quarter over quarter driven by lower
corporate income taxes and growth in electrical infrastructure investment at
FortisAlberta, and lower corporate income taxes and finance charges at the
Terasen Gas companies. The increase was partially offset by lower earnings from
non-regulated hydroelectric generation primarily associated with the loss of
earnings subsequent to the expiration, on April 30, 2009, of the power-for-water
exchange agreement related to the Rankine hydroelectric generating facility in
Ontario.
March 31, 2009/March 31, 2008 - Net earnings applicable to common shares were
$92 million, or $0.54 per common share, for the first quarter of 2009 compared
to earnings of $91 million, or $0.58 per common share, for the first quarter of
2008. Results were driven by growth in electrical infrastructure investment and
customers at the Regulated Electric Utilities in western Canada, partially
offset by lower earnings at the Caribbean Regulated Utilities and Fortis
Properties. Excluding one-time gains of approximately $2 million at Fortis Turks
and Caicos, earnings at the Caribbean Regulated Utilities were $3 million lower
quarter over quarter, resulting from reduced electricity sales attributable to
cooler weather and the impact of the global economic downturn on energy demand
combined with the lower allowed ROAs at Caribbean Utilities and Belize
Electricity. The decrease was partially mitigated by the favourable impact of
foreign exchange rates associated with the strengthening US dollar quarter over
quarter. Fortis Properties' results were reduced by one-time transitional
operating costs associated with the Sheraton Hotel Newfoundland, acquired in
November 2008, and the impact of lower hotel occupancies.
December 31, 2008/December 31, 2007 - Net earnings applicable to common shares
were $76 million, or $0.48 per common share, for the fourth quarter of 2008
compared to earnings of $79 million, or $0.51 per common share, for the fourth
quarter of 2007. Fourth quarter results for 2007 were favourably impacted by
one-time items totalling approximately $13 million related to: (i) the sale of
surplus land at TGI; (ii) the reduction of future income tax liability balances
at Fortis Properties related to lower enacted corporate income tax rates; and
(iii) an interconnection agreement-related refund at FortisOntario. Excluding
these one-time items, earnings were $10 million higher quarter over quarter.
The increase was driven by stronger performance and lower corporate taxes at
FortisAlberta, lower corporate expenses and $1 million of additional earnings
from Caribbean Utilities related to a change in the utility's fiscal year end.
The increase was partially offset by the impact of: (i) a lower allowed ROA at
Belize Electricity, effective July 1, 2008; (ii) an approximate $1 million loss
of revenue at Fortis Turks and Caicos related to Hurricane Ike; and (iii) an
approximate $2 million reduction in fourth quarter earnings at Newfoundland
Power associated with a shift in the quarterly distribution of the utility's
annual purchased power expense.
September 30, 2008/September 30, 2007 - Net earnings applicable to common shares
were $49 million, or $0.31 per common share, for the third quarter of 2008
compared to earnings of $31 million, or $0.20 per common share, for the third
quarter of 2007. Third quarter 2008 results included a tax reduction of
approximately $7.5 million associated with the settlement of historical
corporate tax matters at Terasen. Excluding the tax reduction at Terasen,
earnings for the third quarter of 2008 were $41.5 million or $0.26 per common
share. Excluding the above one-time item, growth in earnings quarter over
quarter was mainly due to higher earnings at Newfoundland Power associated with
a shift in the quarterly distribution of annual purchased power expense, higher
non-regulated hydroelectric production, increased earnings at FortisBC primarily
due to lower energy supply costs and higher earnings at FortisAlberta mainly due
to higher corporate income tax recoveries. The increase was partially offset by
lower earnings at Caribbean Regulated Utilities driven by a 3.25 per cent
reduction in basic electricity rates at Caribbean Utilities, a lower allowed ROA
at Belize Electricity and a loss of revenue at Fortis Turks and Caicos due to
the impact of Hurricane Ike.
SUBSEQUENT EVENT
On July 2, 2009, Fortis issued 30-year $200 million 6.51% unsecured debentures,
the net proceeds of which were used to repay in full the indebtedness
outstanding under the Corporation's committed credit facility and for general
corporate purposes.
OUTLOOK
Gross consolidated capital expenditures are estimated to be more than $1 billion
in 2009 and total approximately $5 billion for the five-year period 2009 through
2013. The Corporation's capital program is expected to drive growth in earnings
and dividends.
The Corporation continues to pursue acquisitions for profitable growth, focusing
on opportunities to acquire regulated natural gas and electric utilities in the
United States and Canada. Fortis will also pursue growth in its non-regulated
businesses in support of its regulated utility growth strategy.
OUTSTANDING SHARE DATA
As at August 4, 2009, the Corporation had issued and outstanding 170.3 million
common shares; 5.0 million First Preference Shares, Series C; 8.0 million First
Preference Shares, Series E; 5.0 million First Preference Shares, Series F; and
9.2 million First Preference Shares, Series G. Only the common shares of the
Corporation have voting rights.
The number of common shares of Fortis that would be issued if all outstanding
stock options, convertible debt and First Preference Shares, Series C and Series
E were converted as at August 4, 2009 is as follows:
---------------------------------------------------------------
---------------------------------------------------------------
Fortis Inc.
Conversion of Securities into Common Shares (Unaudited)
As at August 4, 2009
---------------------------------------------------------------
Security Number of Common Shares (millions)
---------------------------------------------------------------
Stock Options 4.8
---------------------------------------------------------------
Convertible Debt 1.4
---------------------------------------------------------------
First Preference Shares, Series C 5.1
---------------------------------------------------------------
First Preference Shares, Series E 8.2
---------------------------------------------------------------
Total 19.5
---------------------------------------------------------------
---------------------------------------------------------------
Additional information, including the Fortis 2008 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and six months ended June 30, 2009 and 2008
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
June 30, December 31,
2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Restated
- Note 2)
ASSETS
Current assets
Cash and cash equivalents $137 $66
Accounts receivable 449 681
Prepaid expenses 21 17
Regulatory assets (Note 5) 217 157
Inventories (Note 6) 134 229
Future income taxes (Note 14) 28 -
-------------------------------------------------------------------------
986 1,150
Other assets 172 230
Regulatory assets (Note 5) 730 203
Future income taxes (Note 14) 39 54
Utility capital assets 7,425 7,156
Income producing properties 552 540
Intangible assets (Note 7) 260 270
Goodwill 1,573 1,575
-------------------------------------------------------------------------
$11,737 $11,178
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 19) $170 $410
Accounts payable and accrued charges 804 874
Dividends payable 47 47
Income taxes payable 17 66
Regulatory liabilities (Note 5) 60 45
Current installments of long-term debt and
capital lease obligations (Note 8) 185 240
Future income taxes (Note 14) 16 15
-------------------------------------------------------------------------
1,299 1,697
Deferred credits 306 277
Regulatory liabilities (Note 5) 462 401
Future income taxes (Note 14) 538 61
Long-term debt and capital lease obligations
(Note 8) 5,208 4,884
Non-controlling interest 137 145
Preference shares 320 320
-------------------------------------------------------------------------
8,270 7,785
-------------------------------------------------------------------------
Shareholders' equity
Common shares (Note 9) 2,474 2,449
Preference shares 347 347
Contributed surplus 9 9
Equity portion of convertible debentures 6 6
Accumulated other comprehensive loss (Note 11) (60) (52)
Retained earnings 691 634
-------------------------------------------------------------------------
3,467 3,393
-------------------------------------------------------------------------
$11,737 $11,178
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contingent liabilities and commitments (Note 21)
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue $754 $848 $1,955 $1,994
-------------------------------------------------------------------------
Expenses
Energy supply costs 319 439 1,026 1,107
Operating 187 182 379 361
Amortization 92 86 183 169
-------------------------------------------------------------------------
598 707 1,588 1,637
-------------------------------------------------------------------------
Operating income 156 141 367 357
Finance charges (Note 13) 88 90 176 181
-------------------------------------------------------------------------
Earnings before corporate
taxes and non-controlling
interest 68 51 191 176
Corporate taxes (Note 14) 7 19 32 48
-------------------------------------------------------------------------
Net earnings before
non-controlling interest 61 32 159 128
Non-controlling interest 3 - 5 4
-------------------------------------------------------------------------
Net earnings 58 32 154 124
Preference share dividends 5 3 9 4
-------------------------------------------------------------------------
Net earnings applicable to
common shares $53 $29 $145 $120
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per common share
(Note 9)
Basic $0.31 $0.19 $0.85 $0.77
Diluted $0.31 $0.18 $0.83 $0.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Balance at beginning of period $682 $603 $634 $551
Net earnings applicable to
common shares 53 29 145 120
-------------------------------------------------------------------------
735 632 779 671
Dividends on common shares (44) (40) (88) (79)
-------------------------------------------------------------------------
Balance at end of period $691 $592 $691 $592
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings $58 $32 $154 $124
-------------------------------------------------------------------------
Other comprehensive income
Unrealized foreign currency
translation (losses) gains
on net investments in self-
sustaining foreign operations (52) (3) (28) 13
Gains (losses) on hedges of
net investments in self-
sustaining foreign operations 40 3 22 (11)
Corporate tax (expense) recovery (6) - (3) 2
-------------------------------------------------------------------------
Change in unrealized foreign
currency translation (losses)
gains, net of hedging
activities and tax (Note 11) (18) - (9) 4
-------------------------------------------------------------------------
Gain on derivative instruments
designated as cash flow hedges,
net of tax (Note 11) 1 - 1 -
-------------------------------------------------------------------------
Comprehensive income $41 $32 $146 $128
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Restated - Note 2) (Restated - Note 2)
Operating Activities
Net earnings $58 $32 $154 $124
Items not affecting cash
Amortization - utility
capital assets and
income producing properties 81 77 160 151
Amortization - intangibles
assets 9 9 20 18
Amortization - other 2 - 3 -
Future income taxes (Note 14) 4 12 7 15
Non-controlling interest 3 - 5 4
Write-down of deferred
power costs - Belize
Electricity - 18 - 18
Other (4) 1 (7) (4)
Change in long-term regulatory
assets and liabilities 14 1 23 10
-------------------------------------------------------------------------
167 150 365 336
Change in non-cash operating
working capital 108 82 139 89
-------------------------------------------------------------------------
275 232 504 425
-------------------------------------------------------------------------
Investing Activities
Change in other assets and
deferred credits 2 (2) (5) (3)
Capital expenditures - utility
capital assets (264) (204) (474) (369)
Capital expenditures - income
producing properties (6) (5) (11) (8)
Capital expenditures -
intangible assets (7) (13) (11) (19)
Contributions in aid of
construction 10 20 26 32
Proceeds on sale of capital
assets - 1 - 16
Business acquisition (Note 20) (7) - (7) -
-------------------------------------------------------------------------
(272) (203) (482) (351)
-------------------------------------------------------------------------
Financing Activities
Change in short-term
borrowings (89) (163) (239) (196)
Proceeds from long-term debt,
net of issue costs 203 409 401 659
Repayments of long-term debt
and capital lease obligations (85) (200) (91) (205)
Net borrowings (repayments)
under committed credit
facilities 52 (266) 57 (477)
Issue of common shares, net
of costs 11 5 24 11
Issue of preference shares,
net of costs - 223 - 223
Dividends
Common shares (44) (40) (88) (79)
Preference shares (5) (3) (9) (4)
Subsidiary dividends paid
to non-controlling interest (2) (2) (5) (5)
-------------------------------------------------------------------------
41 (37) 50 (73)
-------------------------------------------------------------------------
Effect of exchange rate changes
on cash and cash equivalents (1) - (1) -
-------------------------------------------------------------------------
Change in cash and cash
equivalents 43 (8) 71 1
Cash and cash equivalents,
beginning of period 94 67 66 58
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $137 $59 $137 $59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary information to consolidated statements of cash flows (Note
16)
See accompanying Notes to interim consolidated financial statements.
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 2009 and 2008
(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, and
commercial real estate 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 Corporation's long-term objectives. Each reporting segment operates as an
autonomous unit, assumes profit and loss responsibility and is accountable for
its own resource allocation.
The following summary describes the operations included in each of the
Corporation's reportable segments.
REGULATED UTILITIES
The following summary describes the Corporation's interests in regulated gas and
electric utilities in Canada and the Caribbean by utility:
Regulated Gas Utilities - Canadian
Terasen Gas Companies: Includes Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver
Island) Inc. ("TGVI"), and Terasen Gas (Whistler) Inc. ("TGWI").
TGI is the largest distributor of natural gas in British Columbia, serving
primarily residential, commercial and industrial customers in a service area
that extends from Vancouver to the Fraser Valley and the interior of British
Columbia.
TGVI owns and operates the natural gas transmission pipeline from the Greater
Vancouver area across the Georgia Strait to Vancouver Island and the
distribution system on Vancouver Island and along the Sunshine Coast of British
Columbia, serving primarily residential, commercial and industrial customers.
In addition to providing transmission and distribution services to customers,
TGI and TGVI also obtain natural gas supplies on behalf of most residential and
commercial customers. Gas supplies are sourced primarily from northeastern
British Columbia and, through TGI's Southern Crossing Pipeline, from Alberta.
TGWI owns and operates the newly converted natural gas distribution system in
Whistler, British Columbia, that provides service mainly to residential and
commercial customers.
Regulated Electric Utilities - Canadian
a. FortisAlberta: FortisAlberta owns and operates the electricity distribution
system in a substantial portion of southern and central Alberta.
b. FortisBC: Includes FortisBC Inc., an integrated electric utility operating in
the southern interior of British Columbia. FortisBC Inc. owns four
hydroelectric generating facilities with a combined capacity of 223 megawatts
("MW"). Included with the FortisBC component of the Regulated Electric
Utilities - Canadian segment are the operating, maintenance and management
services relating to the 493-MW Waneta hydroelectric generating facility owned
by Teck Cominco Metals Ltd., the 149-MW Brilliant Hydroelectric Plant and 120-MW
Brilliant Expansion Plant both owned by Columbia Power Corporation and the
Columbia Basin Trust ("CPC/CBT"), the 185-MW Arrow Lakes Hydroelectric Plant
owned by CPC/CBT and the distribution system owned by the City of Kelowna.
c. Newfoundland Power: Newfoundland Power is the principal distributor of
electricity in Newfoundland. Newfoundland Power has an installed generating
capacity of 140 MW, of which 97 MW is hydroelectric generation.
d. Other Canadian: Includes Maritime Electric and FortisOntario. Maritime
Electric is the principal distributor of electricity on Prince Edward Island.
Maritime Electric also maintains on-Island generating facilities with a combined
capacity of 150 MW. FortisOntario provides integrated electric utility service
to customers in Fort Erie, Cornwall, Gananoque and Port Colborne in Ontario.
FortisOntario's operations include Canadian Niagara Power Inc. and Cornwall
Street Railway, Light and Power Company, Limited. Included in Canadian Niagara
Power's accounts is the operation of the electricity distribution business of
Port Colborne Hydro Inc., which has been leased from the City of Port Colborne
under a ten-year lease agreement that expires in April 2012. FortisOntario also
owns a 10 per cent interest in each of Westario Power Holdings Inc., Rideau St.
Lawrence Holdings Inc. and Grimsby Power Inc., three regional electric
distribution companies.
Regulated Electric Utilities - Caribbean
a. Belize Electricity: Belize Electricity is the principal distributor of
electricity in Belize, Central America. The Company has an installed generating
capacity of 34 MW. Fortis holds an approximate 70 per cent controlling
ownership interest in Belize Electricity.
b. Caribbean Utilities: Caribbean Utilities is the sole provider of electricity
on Grand Cayman, Cayman Islands. The Company has an installed generating
capacity of 137 MW. Fortis has an approximate 59.5 per cent controlling
ownership interest in Caribbean Utilities, including an additional 2.7 per cent
interest acquired in July 2009. Caribbean Utilities is a public company traded
on the Toronto Stock Exchange (TSX:CUP.U). Previously, Caribbean Utilities had
an April 30th fiscal year end whereby, up to and including the third quarter of
2008, its financial statements were consolidated in the financial statements of
Fortis on a two-month lag basis. In 2008, Caribbean Utilities changed its
fiscal year end to December 31st. The change in Caribbean Utilities' fiscal
year end eliminates the previous two-month lag in consolidating its financial
results.
c. Fortis Turks and Caicos: Includes P.P.C. Limited and Atlantic Equipment &
Power (Turks and Caicos) Ltd. Fortis Turks and Caicos is the principal
distributor of electricity on the Turks and Caicos Islands. The Company has a
combined diesel-fired generating capacity of 54 MW.
NON-REGULATED - FORTIS GENERATION
a. Belize: Operations consist of the 28-MW Mollejon and 7-MW Chalillo
hydroelectric generating facilities in Belize. All of the output of these
facilities is sold to Belize Electricity under a 50-year power purchase
agreement expiring in 2055. The hydroelectric generation operations in Belize
are conducted through the Corporation's indirect wholly owned subsidiary Belize
Electric Company Limited ("BECOL") under a franchise agreement with the
Government of Belize.
b. Ontario: Includes a 5-MW gas-fired cogeneration plant in Cornwall and six
small hydroelectric generating stations in eastern Ontario with a combined
capacity of 8 MW. Until April 30, 2009, non-regulated operations in Ontario
also included 75 MW of water-right entitlement associated with the Niagara
Exchange Agreement, which expired on April 30, 2009 in accordance with its
terms.
c. Central Newfoundland: Through the Exploits River Hydro Partnership ("Exploits
Partnership"), a partnership between the Corporation, through its wholly owned
subsidiary Fortis Properties, and AbitibiBowater Inc., formerly
Abitibi-Consolidated Company of Canada ("Abitibi"), 36 MW of additional capacity
was developed and installed at two of Abitibi's hydroelectric generating plants
in central Newfoundland. Fortis Properties holds directly a 51 per cent
interest in the Exploits Partnership and Abitibi holds the remaining 49 per cent
interest. The Exploits Partnership sells its output to Newfoundland and
Labrador Hydro Corporation ("Newfoundland Hydro") under a 30-year power purchase
agreement expiring in 2033. Effective February 13, 2009, Fortis commenced
accounting for its investment in the Exploits Partnership using the equity
method of accounting. Previously, the Corporation consolidated the financial
results of the Exploits Partnership in its financial statements (Note 21).
d. British Columbia: Includes the 16-MW run-of-river Walden hydroelectric power
plant near Lillooet, British Columbia. This plant sells its entire output to BC
Hydro under a long-term contract expiring in 2013.
e. Upper New York State: Includes the operations of four hydroelectric
generating stations in Upper New York State, with a combined capacity of
approximately 23 MW, operating under licences from the US Federal Energy
Regulatory Commission. Hydroelectric generation operations in Upper New York
State are conducted through the Corporation's indirect wholly owned subsidiary
FortisUS Energy Corporation ("FortisUS Energy").
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns 21 hotels with more than 4,000 rooms in eight Canadian
provinces and approximately 2.8 million square feet of commercial real estate
primarily in Atlantic Canada.
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not
specifically related to any reportable segment. This segment primarily includes
corporate finance charges, including interest on debt incurred directly by
Fortis and Terasen Inc. ("Terasen") and dividends on preference shares
classified as long-term liabilities; dividends on preference shares classified
as equity; other corporate expenses, including Fortis and Terasen corporate
operating costs, net of recoveries from subsidiaries; interest and miscellaneous
revenues; and corporate income taxes.
Also included in the Corporate and Other segment are the financial results of
CustomerWorks Limited Partnership ("CWLP"). CWLP is a non-regulated
shared-services business in which Terasen holds a 30 per cent interest. CWLP
operates in partnership with Enbridge Inc. and provides customer service
contact, meter reading, billing, credit, and support and collection services to
the Terasen Gas companies and several smaller third parties. CWLP's financial
results are recorded using the proportionate consolidation method of accounting.
While currently not significant, financial results of Terasen Energy Services
Inc. ("TES") are also reported in the Corporate and Other segment. TES is a
non-regulated wholly owned subsidiary of Terasen that provides alternative
energy solutions.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements should be read in conjunction
with the Corporation's 2008 annual audited consolidated financial statements.
Interim results will fluctuate due to the seasonal nature of gas and electricity
demand and water flows, as well as the timing and recognition of regulatory
decisions. Most of the annual earnings of the Terasen Gas companies are
generated in the first and fourth quarters due to seasonality of the business.
Given the diversified group of companies, seasonality may vary.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP") for
interim financial statements, following the same accounting policies and methods
as those used in preparing the Corporation's 2008 annual audited consolidated
financial statements, except as described below.
Effective January 1, 2009, the Corporation adopted the following new accounting
standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Rate-Regulated Operations
Effective January 1, 2009, the Canadian Accounting Standards Board (the "AcSB")
amended: (i) CICA Handbook Section 1100, Generally Accepted Accounting
Principles, removing the temporary exemption providing relief to entities
subject to rate regulation from the requirement to apply the Section to the
recognition and measurement of assets and liabilities arising from rate
regulation; and (ii) Section 3465, Income Taxes to require the recognition of
future income tax liabilities and assets, as well as offsetting regulatory
assets and liabilities, by entities subject to rate regulation.
Effective January 1, 2009, with the removal of the temporary exemption in
Section 1100, the Corporation must now apply Section 1100 to the recognition of
assets and liabilities arising from rate regulation. Certain assets and
liabilities arising from rate regulation continue to have specific guidance
under a primary source of Canadian GAAP that applies only to the particular
circumstances described therein, including those arising under Section 1600,
Consolidated Financial Statements, Section 3061, Property, Plant and Equipment,
Section 3465, Income Taxes, and Section 3475, Disposal of Long-Lived Assets and
Discontinued Operations. The assets and liabilities arising from rate
regulation, as described in Note 5 to these interim consolidated financial
statements and Note 4 to the Corporation's 2008 annual audited consolidated
financial statements, do not have specific guidance under a primary source of
Canadian GAAP. Therefore, Section 1100 directs the Corporation to adopt
accounting policies that are developed through the exercise of professional
judgment and the application of concepts described in Section 1000, Financial
Statement Concepts. In developing these accounting policies, the Corporation
may consult other sources, including pronouncements issued by bodies authorized
to issue accounting standards in other jurisdictions. Therefore, in accordance
with Section 1100, the Corporation has determined that all of its regulatory
assets and liabilities qualify for recognition under Canadian GAAP and this
recognition is consistent with US Statement of Financial Accounting Standards
No. 71, Accounting for the Effects of Certain Types of Regulation. Therefore,
there was no effect on the Corporation's consolidated financial statements as at
January 1, 2009 due to the removal of the temporary exemption from Section 1100.
Effective January 1, 2009, Fortis retroactively recognized future income tax
assets and liabilities and related regulatory liabilities and assets, without
prior period restatement, for the amount of future income taxes expected to be
refunded to, or recovered from, customers in future gas and electricity rates.
Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and
Newfoundland Power used the taxes payable method of accounting for income taxes.
The effect on the Corporation's consolidated financial statements, as at January
1, 2009, of adopting amended Section 3465, Income Taxes included an increase in
total future income tax liabilities and total future income tax assets of $491
million and $24 million, respectively; an increase in regulatory assets and
regulatory liabilities of $535 million and $59 million, respectively; and a
combined $9 million net increase in income taxes payable, deferred credits,
other assets, utility capital assets and goodwill associated with the
reclassification of future income taxes that were previously netted against
these respective balance sheet items. Included in the future income tax assets
and liabilities recorded are the future income tax effects of the subsequent
settlement of the related regulatory assets and liabilities through customer
rates.
Goodwill and Intangible Assets
Effective January 1, 2009, the Corporation retroactively adopted the new CICA
Handbook Section 3064, Goodwill and Intangible Assets. This Section, which
replaces Section 3062, Goodwill and Other Intangible Assets and Section 3450,
Research and Development Costs, establishes standards for the recognition,
measurement and disclosure of goodwill and intangible assets. As at December
31, 2008, the impact of retroactively adopting Section 3064 was a
reclassification of $261 million to intangible assets and related decreases of
$259 million to utility capital assets, $1 million to income producing
properties and $1 million to other assets due to the reclassification of the net
book value of land, transmission and water rights, computer software costs,
franchise costs, customer contracts and other costs.
Credit Risk and the Fair Value of Financial Assets and Financial Liabilities
During the first quarter of 2009, the Corporation adopted the new Emerging
Issues Committee Abstract ("EIC")-173, Credit Risk and the Fair Value of
Financial Assets and Financial Liabilities, which was issued on January 20,
2009. EIC-173 requires that the Corporation's own credit risk and the credit
risk of its counterparties be taken into account in determining the fair value
of a financial instrument. There was no material effect on the Corporation's
interim consolidated financial statements as a result of adopting EIC-173.
3. FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards ("IFRS")
In February 2008, the AcSB confirmed that the use of IFRS will be required in
2011 for publicly accountable enterprises in Canada. In March 2009, the AcSB
issued a second Omnibus Exposure Draft confirming that publicly accountable
enterprises in Canada will be required to apply IFRS, in full and without
modification, beginning January 1, 2011. The Corporation's expected IFRS
transition date of January 1, 2011 will require the restatement, for comparative
purposes, of amounts reported by the Corporation for its year ended December 31,
2010, and of amounts reported on the Corporation's opening IFRS balance sheet as
at January 1, 2010. The AcSB proposes that CICA Handbook Section 1506,
Accounting Changes, paragraph 30, which would require an entity to disclose
information relating to a new primary source of GAAP that has been issued but is
not yet effective and that the entity has not applied, not be applied with
respect to this Exposure Draft. Fortis is continuing to assess the financial
reporting impacts on its future financial position and results of operations as
a result of adopting IFRS, including monitoring any International Accounting
Standards Board ("IASB") initiatives with the potential to impact rate-regulated
accounting under IFRS. In July 2009, the IASB issued an Exposure Draft on
Rate-Regulated Activities with a final standard expected to be issued in 2010.
The Exposure Draft states that regulatory assets and liabilities arising from
activities subject to cost-of-service regulation may be recognized under IFRS
when certain conditions are met. The ability to record regulatory assets and
liabilities should reduce the earnings' volatility at the Corporation's
regulated utilities that may have otherwise resulted under IFRS. Uncertainty as
to the final outcome of this Exposure Draft and the final standard on accounting
for rate-regulated activities under IFRS has resulted in the Corporation being
unable to reasonably estimate and conclude on the impact on the Corporation's
future financial position and results of operations with respect to differences,
if any, in accounting for rate-regulated activities under IFRS versus Canadian
GAAP. Fortis anticipates a significant increase in disclosure requirements
resulting from the adoption of IFRS and is identifying and assessing these
additional disclosure requirements, as well as systems changes that will be
necessary to compile the required disclosures.
Business Combinations
In January 2009, the AcSB issued new CICA Handbook Section 1582, Business
Combinations, together with Section 1601, Consolidated Financial Statements and
Section 1602, Non-Controlling Interests. These new standards are effective for
fiscal years beginning on or after January 1, 2011. As a result of adopting
Section 1582, changes in the determination of the fair value of the assets and
liabilities of the acquiree will result in a different calculation of goodwill
with respect to future acquisitions. Such changes include the expensing of
acquisition-related costs incurred during a business acquisition, rather than
recording them as a capital transaction, and the disallowance of recording
restructuring accruals by the acquirer.
Section 1582 will affect the recognition of business combinations completed by
the Corporation on or after January 1, 2011 and, as a result, may have a
material impact on the Corporation's consolidated earnings and financial
position.
Section 1601 establishes standards for the preparation of consolidated financial
statements. Section 1602 establishes standards for accounting for a
non-controlling interest in a subsidiary in consolidated financial statements
subsequent to a business combination. The adoption of Sections 1601 and 1602
will result in non-controlling interests being presented as components of
equity, rather than as liabilities, on the consolidated balance sheet.
Also, net earnings and components of other comprehensive income attributable to
the owners of the parent and to the non-controlling interests are required to be
separately disclosed on the statement of earnings. The adoption of Sections 1601
and 1602 is not expected to have a material impact on the Corporation's
consolidated earnings, cash flows or financial position.
Financial Instruments
In June 2009, the AcSB issued amendments to the CICA Handbook Section 3862,
Financial Instruments - Disclosures, to include additional disclosure
requirements about the fair value measurement of financial instruments and to
enhance liquidity risk disclosures. The amendments are effective for annual
financial statements relating to fiscal years ending after September 30, 2009.
The Corporation will reflect the additional disclosures in its 2009 annual
audited consolidated financial statements.
4. USE OF ESTIMATES
The preparation of the Corporation's interim consolidated financial statements
in accordance with Canadian GAAP requires management to make estimates and
judgments that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenue and expenses during the
reporting periods. Estimates and judgments are based on historical experience,
current conditions and various other assumptions believed to be reasonable under
the circumstances. Additionally, certain estimates and judgments are necessary
since the regulatory environments in which the Corporation's utilities operate
often require amounts to be recorded at estimated values until these amounts are
finalized pursuant to regulatory decisions or other regulatory proceedings. Due
to changes in facts and circumstances and the inherent uncertainty involved in
making estimates, actual results may differ significantly from current
estimates. Estimates and judgments are reviewed periodically and, as
adjustments become necessary, are reported in earnings in the period they become
known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates, including that related to
contingencies, during the six months ended June 30, 2009, except for those
described in Notes 14 and 21 to these interim consolidated financial statements.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A description of the nature of the regulatory assets and liabilities is
provided below and in Note 4 to the Corporation's 2008 annual audited
consolidated financial statements.
As at As at
($ millions) June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Assets
Future income taxes (Note 2) 538 -
Rate stabilization accounts - Terasen Gas
companies 112 76
Rate stabilization accounts - electric utilities 75 78
Alberta Electric System Operator ("AESO") charges
deferral 66 64
Regulatory other post-employment benefit ("OPEB")
plan asset 55 51
Income taxes recoverable on OPEB plans 18 18
Point Lepreau replacement energy deferral (1) 13 -
Deferred pension costs 7 7
Southern Crossing Pipeline tax reassessment 7 7
Energy management costs 7 7
Deferred capital asset amortization 6 8
Residential unbundling 5 7
Other regulatory assets 38 37
-------------------------------------------------------------------------
Total regulatory assets 947 360
Less: current portion (217) (157)
-------------------------------------------------------------------------
Long-term regulatory assets 730 203
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at As at
($ millions) June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulatory Liabilities
Future asset removal and site restoration
provision 340 337
Future income taxes (Note 2) 49 -
Rate stabilization accounts - Terasen Gas
companies 47 32
Rate stabilization accounts - electric utilities 16 9
Performance-based rate-setting incentive
liabilities 15 13
Unbilled revenue liability 14 15
Southern Crossing Pipeline deferral 6 9
Fair value of the foreign exchange forward
contract 4 7
Pension deferral 4 4
Other regulatory liabilities 27 20
-------------------------------------------------------------------------
Total regulatory liabilities 522 446
Less: current portion (60) (45)
-------------------------------------------------------------------------
Long-term regulatory liabilities 462 401
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Maritime Electric has regulatory approval to defer the cost of
replacement energy related to the New Brunswick Power Point Lepreau
Nuclear Generating Station during its refurbishment outage. The nature
and timing of the future recovery of the amount will be determined by
the regulator later in 2009.
6. INVENTORIES
As at As at
($ millions) June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gas in storage 116 212
Materials and supplies 18 17
-------------------------------------------------------------------------
134 229
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the three and six months ended June 30, 2009, inventories of $156 million
and $624 million, respectively, were expensed and reported in energy supply
costs in the interim consolidated statement of earnings ($256 million and $693
million for the three and six months ended June 30, 2008, respectively).
Inventories expensed to operating expenses were $4 million and $7 million for
the three and six months ended June 30, 2009, respectively ($3 million and $6
million for the three and six months ended June 30, 2008, respectively), which
included $2 million and $4 million, respectively, for food and beverage costs at
Fortis Properties ($2 million and $4 million for the three and six months ended
June 30, 2008, respectively).
7. INTANGIBLE ASSETS
As at June 30, 2009
---------------------------------------------------------------------
---------------------------------------------------------------------
Amortization
Rates Accumulated Net Book
($ millions) (%) Cost Amortization Value
---------------------------------------------------------------------
---------------------------------------------------------------------
Computer software 1 - 5 318 (159) 159
Land, transmission and water
rights 1 - 17 130 (38) 92
Franchise fees, customer
contracts and other 3 - 22 16 (7) 9
---------------------------------------------------------------------
464 (204) 260
---------------------------------------------------------------------
---------------------------------------------------------------------
As at December 31, 2008
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated Net Book
($ millions) Cost Amortization Value
---------------------------------------------------------------------
---------------------------------------------------------------------
Computer software 310 (142) 168
Land, transmission and water rights 127 (36) 91
Franchise fees, customer contracts and
other 16 (5) 11
---------------------------------------------------------------------
453 (183) 270
---------------------------------------------------------------------
---------------------------------------------------------------------
There was no impairment of intangible assets for the six months ended June 30,
2009 and for the year ended December 31, 2008.
Additions to intangible assets for the three and six months ended June 30, 2009
were $7 million and $11 million, respectively, of which approximately $6 million
and $9 million, respectively, were developed internally.
Included in the cost of land, transmission and water rights is a total of $58
million (December 31, 2008 - $57 million) not subject to amortization.
8. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at As at
($ millions) June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt and capital lease
obligations 5,158 4,934
Long-term classification of committed credit
facilities (Note 19) 272 224
Deferred debt financing costs (37) (34)
-------------------------------------------------------------------------
Total long-term debt and capital lease
obligations 5,393 5,124
Less: Current installments of long-term debt
and capital lease obligations (185) (240)
-------------------------------------------------------------------------
5,208 4,884
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In June 2009, FortisBC issued 30-year $105 million 6.10% unsecured debentures.
In May 2009, Newfoundland Power issued 30-year $65 million 6.606% first mortgage
sinking fund bonds.
In May 2009, Caribbean Utilities closed the first tranche of a 15-year US$40
million private placement of 7.50% senior unsecured notes. The first tranche
was in the amount of US$30 million and the second tranche of US$10 million
closed in July 2009.
In February 2009, FortisAlberta issued 30-year $100 million 7.06% unsecured
debentures.
In February 2009, TGI issued 30-year $100 million 6.55% unsecured debentures.
During the first quarter of 2009, Fortis began accounting for its investment in
the Exploits Partnership using the equity method of accounting (Note 21). As a
result, the Exploits Partnership term loan of approximately $60 million
(December 31, 2008 - $61 million) classified as current as at December 31, 2008
is no longer being consolidated in the financial statements of Fortis, effective
February 13, 2009.
9. COMMON SHARES
Authorized: an unlimited number of common shares without nominal or par value.
As at As at
Issued and Outstanding June 30, 2009 December 31, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares 170,311 2,474 169,191 2,449
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares issued during the period were as follows:
Quarter Ended Year-to-date
June 30, 2009 June 30, 2009
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening balance 169,759 2,462 169,191 2,449
Consumer Share Purchase
Plan 16 - 31 1
Dividend Reinvestment
Plan 194 5 564 13
Employee Share Purchase
Plan 69 2 203 5
Stock Option Plans 273 5 322 6
-------------------------------------------------------------------------
Ending balance 170,311 2,474 170,311 2,474
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effective March 1, 2009, the Corporation's Amended and Restated Dividend
Reinvestment and Share Purchase Plan provides a 2 per cent discount on the
purchase of common shares, issued from treasury, with reinvested dividends.
The Corporation calculates earnings per common share on the weighted average
number of common shares outstanding. The weighted average number of common
shares outstanding was 170.0 million and 157.0 million for the quarters ended
June 30, 2009 and June 30, 2008, respectively, and 169.7 million and 156.8
million year-to-date June 30, 2009 and June 30, 2008, respectively.
Diluted earnings per common share are calculated using the treasury stock method
for options and the "if-converted" method for convertible securities.
Earnings per common share are as follows:
Quarter Ended June 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic Earnings
per Common
Share 53 170.0 $0.31 29 157.0 $0.19
---------------------------------------------------------------------------
Effect of
potential
dilutive
securities:
Stock options - 0.7 - 1.1
Preference shares
(Note 13) 4 13.9 4 12.9
Convertible
debentures 1 1.4 1 1.4
---------------------------------------------------------------------------
58 186.0 34 172.4
Deduct
anti-dilutive
impacts:
Preference
shares (2) (5.3) (4) (12.9)
Convertible
debentures (1) (1.4) (1) (1.4)
---------------------------------------------------------------------------
Diluted Earnings
per Common Share 55 179.3 $0.31 29 158.1 $0.18
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date June 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2009 2008
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Earnings Shares per
($ (in Common ($ (in Common
millions) millions) Share millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Basic Earnings
per Common
Share 145 169.7 $0.85 120 156.8 $0.77
---------------------------------------------------------------------------
Effect of
potential
dilutive
securities:
Stock options - 0.7 - 1.1
Preference
shares (Note 13) 8 13.9 8 12.9
Convertible
debentures 1 1.4 1 1.6
---------------------------------------------------------------------------
154 185.7 129 172.4
Deduct
anti-dilutive
impacts:
Convertible
debentures (1) (1.4) - -
---------------------------------------------------------------------------
Diluted Earnings
per Common Share 153 184.3 $0.83 129 172.4 $0.75
---------------------------------------------------------------------------
---------------------------------------------------------------------------
10. STOCK-BASED COMPENSATION PLANS
During the six months ended June 30, 2009, 30,336 Deferred Share Units ("DSUs")
were granted to the Corporation's Board of Directors, representing the equity
component of their annual compensation and 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 January 2009, 3,632 DSUs were
paid out to a retired member of the Board of Directors of Fortis at $23.74 per
DSU for a total of approximately $0.1 million.
In March 2009, 31,353 Performance Share Units ("PSUs") were paid out to the
President and Chief Executive Officer ("CEO") of the Corporation, as determined
by the Human Resources Committee of the Board of Directors of Fortis, at $23.39
per PSU for a total of approximately $0.7 million. The payout was made upon the
three-year maturation period in respect of the PSU grant made in March 2006 and
the President and CEO satisfying the payment requirements. In March 2009,
40,000 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.
In March 2009, the Corporation granted 1,037,156 options to purchase common
shares under its 2006 Stock Option Plan at the five-day volume weighted average
trading price of $22.29 immediately preceding the date of grant. The options
vest evenly over a four-year period on each anniversary of the date of grant.
The options expire seven years after the date of grant. The fair value of each
option granted was $4.10 per option.
The fair value was estimated on the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.19
Expected volatility (%) 24.3
Risk-free interest rate (%) 3.75
Weighted average expected life (years) 4.5
At June 30, 2009, 4.9 million stock options were outstanding and 2.7 million
stock options were vested.
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, gains and losses on
cash flow hedging activities and gains and losses on discontinued cash flow
hedging activities.
Quarter Ended June 30, 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) April 1 change June 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency translation
losses, net of hedging activities and tax (37) (18) (55)
(Losses) gains on derivative instruments
designated as cash flow hedges, net of tax (1) 1 -
Net losses on derivative instruments
previously discontinued as cash flow hedges,
net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive Loss (43) (17) (60)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarter Ended June 30, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) April 1 change June 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency translation
losses, net of hedging activities and tax (78) - (78)
(Losses) gains on derivative instruments
designated as cash flow hedges, net of tax (1) - (1)
Net losses on derivative instruments previously
discontinued as cash flow hedges, net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive Loss (84) - (84)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year-to-date 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change June 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency translation
(losses) gains, net of hedging activities
and tax (46) (9) (55)
(Losses) gains on derivative instruments
designated as cash flow hedges, net of tax (1) 1 -
Net losses on derivative instruments previously
discontinued as cash flow hedges, net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive (Loss) Income (52) (8) (60)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year-to-date 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change June 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unrealized foreign currency translation
(losses) gains, net of hedging activities
and tax (82) 4 (78)
(Losses) gains on derivative instruments
designated as cash flow hedges, net of tax (1) - (1)
Net losses on derivative instruments previously
discontinued as cash flow hedges, net of tax (5) - (5)
-------------------------------------------------------------------------
Accumulated Other Comprehensive (Loss) Income (88) 4 (84)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
12. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans, defined contribution pension plans and group
registered retirement savings plans ("RRSPs") for its employees. The cost of
providing the defined benefit arrangements was $7 million for the quarter ended
June 30, 2009 ($7 million for the quarter ended June 30, 2008) and $13 million
year-to-date June 30, 2009 ($14 million year-to-date June 30, 2008). The cost
of providing the defined contribution arrangements and group RRSPs was $2
million for the quarter ended June 30, 2009 ($2 million for the quarter ended
June 30, 2008) and $6 million year-to-date June 30, 2009 ($5 million
year-to-date June 30, 2008).
13. FINANCE CHARGES
Quarter Ended Year-to-date
June 30 June 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest - Long-term debt and capital lease
obligations 86 85 170 168
- Short-term borrowings 2 3 6 10
Interest charged to construction (4) (2) (8) (4)
Interest earned - - - (1)
Dividends on preference shares classified as debt 4 4 8 8
-------------------------------------------------------------------------
88 90 176 181
-------------------------------------------------------------------------
-------------------------------------------------------------------------
14. CORPORATE TAXES
Prior to January 1, 2009, the Terasen Gas companies, FortisAlberta, FortisBC and
Newfoundland Power used the taxes payable method of accounting for income taxes.
The effect on the Corporation's consolidated financial statements, as at
January 1, 2009, of adopting amended Section 3465, Income Taxes, included an
increase in total future income tax liabilities and total future income tax
assets of $491 million and $24 million, respectively; an increase in regulatory
assets and regulatory liabilities of $535 million and $59 million, respectively;
and a combined $9 million net increase in income taxes payable, deferred
credits, other assets, utility capital assets and goodwill, associated with the
reclassification of future income taxes that were previously netted against
these respective balance sheet items. Included in the future income tax assets
and liabilities recorded are the future income tax effects of the subsequent
settlement of the related regulatory assets and liabilities through customer
rates.
Future income taxes are provided for temporary differences. Future income tax
assets and liabilities are comprised of the following:
As at As at
June 30, December 31,
($ millions) 2009 2008
-------------------------------------------------------------------
-------------------------------------------------------------------
Future income tax liability (asset)
Utility capital assets 482 17
Income producing properties 26 26
Regulatory assets 30 35
Intangible assets 7 3
Other assets 24 2
Deferred credits (43) (14)
Loss carryforwards (29) (28)
Share issue and debt financing costs (6) (14)
Unrealized foreign currency translation losses
on long-term debt (1) (5)
Regulatory liabilities (3) -
-------------------------------------------------------------------
Net future income tax liability 487 22
-------------------------------------------------------------------
-------------------------------------------------------------------
Current future income tax asset (28) -
Current future income tax liability 16 15
Long-term future income tax asset (39) (54)
Long-term future income tax liability 538 61
-------------------------------------------------------------------
Net future income tax liability 487 22
-------------------------------------------------------------------
-------------------------------------------------------------------
The adoption of amended Section 3465, Income Taxes on January 1, 2009 also
resulted in additional future income tax expense of $9 million for the quarter
ended June 30, 2009 and a reduction in future income tax expense of $1 million
year-to-date June 30, 2009 and offsetting regulatory adjustments to future
income tax expense for the same amounts during those periods. The regulatory
adjustment represents the difference between the future income tax expense
recognized under amended Section 3465, Income Taxes and that recovered from
customers in rates during the quarter and year-to-date period ended June 30,
2009.
The components of the provision for corporate taxes are as follows:
Quarter Ended Year-to-date
June 30 June 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current taxes - Canadian 3 7 25 33
-------------------------------------------------------------------------
Future income taxes - Canadian 13 12 6 15
(Less) Add: Regulatory adjustment (9) - 1 -
-------------------------------------------------------------------------
4 12 7 15
-------------------------------------------------------------------------
Corporate taxes 7 19 32 48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate taxes differ from the amount that would be expected to be generated by
applying the enacted combined Canadian federal and provincial statutory tax rate
to earnings before corporate taxes and non-controlling interest. The following
is a reconciliation of consolidated statutory taxes to consolidated effective
taxes.
Quarter Ended Year-to-date
June 30 June 30
($ millions, except as noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Combined Canadian federal and provincial
statutory income tax rate 33% 33.5% 33% 33.5%
-------------------------------------------------------------------------
Statutory income tax rate applied to earnings
before corporate taxes and non-controlling
interest 22 17 63 59
Preference share dividends 2 3 3 4
Difference between Canadian statutory rate
and rates applicable to foreign subsidiaries (4) 1 (7) (2)
Difference in Canadian provincial statutory
rates applicable to subsidiaries in different
Canadian jurisdictions (1) (1) (4) (3)
Items capitalized for accounting but expensed
for income tax purposes (10) (2) (20) (12)
Pension costs - - (1) (1)
Other (2) 1 (2) 3
-------------------------------------------------------------------------
Corporate taxes 7 19 32 48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effective tax rate 10.3% 37.3% 16.8% 27.3%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2009, the Corporation had approximately $111 million (December
31, 2008 - $104 million) in non-capital and capital loss carryforwards of which
$11 million (December 31, 2008 - $12 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2009 and 2029.
15. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Quarter Terasen
ended Gas Total
June Companies- Fortis Fortis NF Other Electric Electric
30, 2009 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 289 81 55 119 63 318 82
Energy supply
costs 156 - 13 70 40 123 45
Operating
expenses 62 31 17 13 7 68 14
Amortization 26 23 9 11 5 48 9
--------------------------------------------------------------------------
Operating income 45 27 16 25 11 79 14
Finance charges 29 13 8 9 4 34 4
Corporate taxes
(recovery) 2 (3) 1 5 3 6 1
Non-controlling
interest - - - - - - 2
--------------------------------------------------------------------------
Net earnings
(loss) 14 17 7 11 4 39 7
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 14 17 7 11 4 39 7
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 154
Identifiable
assets 3,838 1,767 1,137 1,156 533 4,593 847
--------------------------------------------------------------------------
Total assets 4,746 1,994 1,358 1,156 596 5,104 1,001
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(3) 64 116 27 19 11 173 30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended
June 30, 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 390 75 53 120 61 309 78
Energy supply
costs 256 - 12 70 40 122 64
Operating
expenses 62 32 17 13 7 69 12
Amortization 25 21 8 12 5 46 8
--------------------------------------------------------------------------
Operating income 47 22 16 25 9 72 (6)
Finance charges 30 11 7 9 5 32 2
Corporate taxes
(recovery) 5 4 2 6 2 14 (1)
Non-controlling
interest - - - - - - (2)
--------------------------------------------------------------------------
Net earnings
(loss) 12 7 7 10 2 26 (5)
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings
(loss)
applicable to
common shares 12 7 7 10 2 26 (5)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 130
Identifiable
assets 3,587 1,414 933 983 501 3,831 683
--------------------------------------------------------------------------
Total assets 4,496 1,641 1,154 983 564 4,342 813
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures
(3) 56 79 26 17 10 132 23
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NON-REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended Corporate Inter-
June 30, 2009 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 9 58 7 (9) 754
Energy supply costs - - - (5) 319
Operating expenses 2 38 4 (1) 187
Amortization 2 4 3 - 92
--------------------------------------------------------------------------
Operating income 5 16 - (3) 156
Finance charges 1 5 18 (3) 88
Corporate taxes
(recovery) - 3 (5) - 7
Non-controlling interest 1 - - - 3
--------------------------------------------------------------------------
Net earnings (loss) 3 8 (13) - 58
Preference share
dividends - - 5 - 5
--------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 3 8 (18) - 53
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,573
Identifiable assets 207 577 141 (39) 10,164
--------------------------------------------------------------------------
Total assets 207 577 141 (39) 11,737
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 4 5 1 - 277
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended
June 30, 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 22 54 5 (10) 848
Energy supply costs 2 - - (5) 439
Operating expenses 4 35 3 (3) 182
Amortization 3 3 1 - 86
--------------------------------------------------------------------------
Operating income 13 16 1 (2) 141
Finance charges 2 6 20 (2) 90
Corporate taxes
(recovery) 2 3 (4) - 19
Non-controlling
interest 2 - - - -
--------------------------------------------------------------------------
Net earnings (loss) 7 7 (15) - 32
Preference share
dividends - - 3 - 3
--------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 7 7 (18) - 29
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,550
Identifiable assets 239 539 116 (16) 8,979
--------------------------------------------------------------------------
Total assets 239 539 116 (16) 10,529
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 4 5 2 - 222
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties and
intangible assets
REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gas Utilities Electric Utilities
--------------------------------------------------------------------------
Terasen Gas Total
Year-to-date Companies Fortis Fortis NF Other Electric Electric
June 30, 2009 -Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 958 160 127 288 133 708 165
Energy supply
costs 624 - 35 197 87 319 91
Operating
expenses 129 65 34 27 14 140 28
Amortization 51 45 19 22 9 95 20
--------------------------------------------------------------------------
Operating income 154 50 39 42 23 154 26
Finance charges 61 24 15 17 9 65 8
Corporate taxes
(recovery) 21 (3) 3 8 5 13 1
Non-controlling
interest - - - - - - 4
--------------------------------------------------------------------------
Net earnings (loss) 72 29 21 17 9 76 13
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 72 29 21 17 9 76 13
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 908 227 221 - 63 511 154
Identifiable
assets 3,838 1,767 1,137 1,156 533 4,593 847
--------------------------------------------------------------------------
Total assets 4,746 1,994 1,358 1,156 596 5,104 1,001
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 114 206 49 32 23 310 50
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-date
June 30, 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue 1,025 148 119 284 131 682 153
Energy supply
costs 693 - 33 192 89 314 104
Operating
expenses 123 65 33 27 14 139 23
Amortization 49 41 17 22 9 89 15
--------------------------------------------------------------------------
Operating income 160 42 36 43 19 140 11
Finance charges 63 20 14 17 9 60 7
Corporate taxes
(recovery) 27 4 3 10 4 21 -
Non-controlling
interest - - - - - - 2
--------------------------------------------------------------------------
Net earnings
(loss) 70 18 19 16 6 59 2
Preference share
dividends - - - - - - -
--------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 70 18 19 16 6 59 2
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 130
Identifiable
assets 3,587 1,414 933 983 501 3,831 683
--------------------------------------------------------------------------
Total assets 4,496 1,641 1,154 983 564 4,342 813
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures (3) 96 151 50 30 17 248 34
--------------------------------------------------------------------------
--------------------------------------------------------------------------
NON-REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year-to-date Inter-
June 30, 2009 Fortis Fortis Corporate segment
($ millions) Generation Properties and Other eliminations Consolidated
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 25 105 14 (20) 1,955
Energy supply
costs 1 - - (9) 1,026
Operating
expenses 6 72 7 (3) 379
Amortization 4 8 5 - 183
---------------------------------------------------------------------------
Operating income 14 25 2 (8) 367
Finance charges 2 11 37 (8) 176
Corporate taxes
(recovery) 2 4 (9) - 32
Non-controlling
interest 1 - - - 5
---------------------------------------------------------------------------
Net earnings
(loss) 9 10 (26) - 154
Preference
share dividends - - 9 - 9
---------------------------------------------------------------------------
Net earnings
(loss)
applicable
to common
shares 9 10 (35) - 145
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,573
Identifiable
assets 207 577 141 (39) 10,164
---------------------------------------------------------------------------
Total assets 207 577 141 (39) 11,737
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) 11 10 1 - 496
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date
June 30, 2008
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 41 99 12 (18) 1,994
Energy supply
costs 4 - - (8) 1,107
Operating expenses 8 66 6 (4) 361
Amortization 5 7 4 - 169
---------------------------------------------------------------------------
Operating income 24 26 2 (6) 357
Finance charges 4 12 41 (6) 181
Corporate taxes
(recovery) 5 4 (9) - 48
Non-controlling
interest 2 - - - 4
---------------------------------------------------------------------------
Net earnings (loss) 13 10 (30) - 124
Preference share
dividends - - 4 - 4
---------------------------------------------------------------------------
Net earnings (loss)
applicable to
common shares 13 10 (34) - 120
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,550
Identifiable
assets 239 539 116 (16) 8,979
---------------------------------------------------------------------------
Total assets 239 539 116 (16) 10,529
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures (3) 7 8 3 - 396
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(3) Relates to utility capital assets, including amounts for AESO
transmission capital projects, and income producing properties and
intangible assets
Inter-segment transactions are in the normal course of operations and are
measured at the exchange amount, which is the amount of consideration
established and agreed to by the related parties. The significant inter-segment
transactions primarily related to the sale of energy from Fortis Generation to
Belize Electricity and FortisOntario, electricity sales from Newfoundland Power
to Fortis Properties and finance charges on inter-segment borrowings. The
significant inter-segment transactions for the three and six months ended June
30, 2009 and 2008 were as follows.
Inter-Segment Transactions
Quarter Ended Year-to-date
June 30 June 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales from Fortis Generation to Regulated
Electric Utilities - Caribbean 4 4 8 7
Sales from Fortis Generation to Other
Canadian Electric Utilities 1 1 1 1
Sales from Newfoundland Power to Fortis
Properties 1 1 2 2
Inter-segment finance charges on borrowings
from:
Corporate to Regulated Electric Utilities
- Canadian - 1 1 1
Corporate to Regulated Electric Utilities
- Caribbean 1 2 3 2
Corporate to Fortis Properties 2 2 4 4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-date
June 30 June 30
($ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest paid 99 102 184 181
Income taxes paid 15 3 80 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
17. CAPITAL MANAGEMENT
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital in order to allow the utilities
to fund the maintenance and expansion of infrastructure. Fortis raises debt at
the subsidiary level in support of infrastructure investment to ensure
regulatory transparency, tax efficiency and financing flexibility. To help
ensure access to capital, the Corporation targets a consolidated long-term
capital structure containing approximately 40 per cent equity, including
preference shares, and 60 per cent debt, as well as investment-grade credit
ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in the
utilities' customer rates.
The consolidated capital structure of Fortis is presented in the following table.
As at As at
June 30, December 31,
2009 2008
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash) (1) 5,426 58.9 5,468 59.5
Preference shares (2) 667 7.2 667 7.3
Common shareholders' equity 3,120 33.9 3,046 33.2
-------------------------------------------------------------------------
Total 9,213 100.0 9,181 100.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Includes preference shares classified as both long-term liabilities and
equity
Certain of the Corporation's long-term debt obligations have covenants
restricting the issuance of additional debt such that consolidated debt cannot
exceed 70 per cent of the Corporation's consolidated capital structure, as
defined by the long-term debt agreements. Fortis and its subsidiaries, except
for Belize Electricity and the Exploits Partnership as described below, were in
compliance with their debt covenants as at June 30, 2009.
As a result of the regulator's Final Decision on Belize Electricity's 2008/2009
Rate Application, Belize Electricity does not meet certain debt covenant
financial ratios related to loans totalling $8 million (BZ$14 million), as at
June 30, 2009, with the International Bank for Reconstruction and Development
and the Caribbean Development Bank. The Company has informed the lenders of the
defaults and has requested appropriate waivers.
As the hydroelectric assets and water rights of the Exploits Partnership had
been provided as security for the Exploits Partnership's term loan, the recent
expropriation of such assets and rights by the Government of Newfoundland and
Labrador constituted an event of default under the loan. The loan is without
recourse to Fortis and was approximately $60 million as at June 30, 2009. The
lenders of the term loan have not demanded accelerated repayment. See Notes 8
and 21 for further information on the Exploits Partnership.
The Corporation's consolidated credit facilities are discussed further under
"Liquidity Risk" in Note 19.
18. FINANCIAL INSTRUMENTS
Fair Values
There was no change during the six months ended June 30, 2009 in the designation
of the Corporation's financial instruments from that disclosed in the
Corporation's 2008 annual audited consolidated financial statements. The
carrying values of financial instruments included in current assets, current
liabilities, other assets and deferred credits in the consolidated balance
sheets of Fortis approximate their fair values, reflecting the short-term
maturity, normal trade credit terms and/or the nature of these instruments. The
carrying values and fair values of the Corporation's consolidated long-term debt
and preference shares were as follows:
As at As at
June 30, December 31,
2009 2008
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt, including
current portion (1)(2) 5,393 5,649 5,122 5,040
Preference shares, classified
as debt (1)(3) 320 334 320 329
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Carrying value is measured at amortized cost using the effective
interest rate method.
(2) Carrying value as at June 30, 2009 excludes unamortized deferred
financing costs of $37 million (December 31, 2008 - $34 million).
(3) Preference shares classified as equity are excluded from the
requirements of the CICA Handbook Section 3855, Financial Instruments,
Recognition and Measurement; however, the estimated fair value of the
Corporation's $347 million preference shares classified as equity was
$336 million as at June 30, 2009 (December 31, 2008 - carrying value
$347 million; fair value $268 million).
The fair value of long-term debt is calculated by using quoted market prices,
when available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a market credit risk
premium equal to that of issuers of similar credit quality. Since the
Corporation does not intend to settle the long-term debt prior to maturity, the
fair value estimate does not represent an actual liability and, therefore, does
not include exchange or settlement costs. The fair value of the Corporation's
preference shares is determined using quoted market prices.
The Corporation and its subsidiaries hedge exposures to fluctuations in interest
rates, foreign exchange rates and natural gas prices through the use of
derivative financial instruments. The Corporation does not hold or issue
derivative financial instruments for trading purposes. The following table
summarizes the valuation of the Corporation's derivative financial instruments.
As at As at
June 30, 2009 December 31, 2008
Term to Number Carrying Estimated Carrying Estimated
maturity of Value Fair Value Value Fair Value
Asset (years) Contracts ($ ($ ($ ($
(Liability) millions) millions) millions) millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest
rate less
swaps (1) than 2 2 - - - -
Foreign
exchange
forward
contract approx.
(2) 2 1 4 4 7 7
Natural gas
derivatives:
(3)
Swaps and Up to
options 5.25 223 (162) (162) (84) (84)
Gas purchase
contract Up to
premiums 2.25 51 (6) (6) (8) (8)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) The interest rate swap contracts mature in July 2009 and October 2010.
The contracts have the effect of fixing the rate of interest on the
non-revolving credit facilities of Fortis Properties at 6.16 per cent
and 5.32 per cent, respectively.
(2) The fair value of the foreign exchange forward contract was recorded in
accounts receivable as at June 30, 2009 and December 31, 2008.
(3) The fair values of the natural gas derivatives were recorded in
accounts payable as at June 30, 2009 and December 31, 2008.
The fair value of the Corporation's financial instruments, including
derivatives, reflects a point-in-time estimate 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 earnings or cash flows.
19. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit risk Risk that a third party to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.
Liquidity risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market risk Risk that the fair value or future cash flows of a
financial instrument will fluctuate due to changes in
market prices. The Corporation is exposed to market risks
related to foreign exchange, interest rates and commodity
prices.
Credit Risk
For cash and cash equivalents, trade and other accounts receivable, and other
receivables due from customers, the Corporation's credit risk is limited to the
carrying value on the 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 and these include requiring customer deposits and 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
and, as at June 30, 2009, its gross credit risk exposure was approximately $88
million, representing the projected value of retailer billings over a 60-day
period. The Company has reduced its exposure to approximately $3 million by
obtaining from the retailers either a cash deposit, bond, letter of credit, an
investment-grade credit rating from a major rating agency or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The Terasen Gas companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments, including
natural gas derivatives. The Terasen Gas companies are also exposed to
significant credit risk on physical off-system sales. To mitigate credit risk,
the Terasen Gas companies deal with high credit-quality institutions, in
accordance with established credit-approval practices. The counterparties with
which the Terasen Gas companies have significant transactions are A-rated
entities or better. The Company uses netting arrangements to reduce credit risk
and net settles payments with counterparties where net settlement provisions
exist.
The aging analysis of the Corporation's consolidated accounts receivable
(excluding derivative financial instruments recorded in accounts receivable) is
as follows:
As at As at As at As at
June 30, March 31, December 31, June 30,
($ millions) 2009 2009 2008 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Not past due 367 610 587 431
Past due 0-30 days 53 93 70 66
Past due 31-60 days 22 23 14 18
Past due 61 days and over 21 20 19 22
-------------------------------------------------------------------------
463 746 690 537
Less: allowance for
doubtful accounts (18) (19) (16) (14)
-------------------------------------------------------------------------
445 727 674 523
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2009, other receivables due from customers of $7 million
(included in other assets) and the receivable associated with the foreign
exchange forward contract of $4 million (included in accounts receivable) will
be received over the next five years, with $6 million expected to be received in
2009, $3 million over 2010 and 2011, $1 million over 2012 and 2013 and $1
million in 2014.
Liquidity Risk
The Corporation's financial position could be adversely affected if it, or its
operating subsidiaries, fail 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 results of operations and financial position
of the Corporation and its subsidiaries, conditions in the capital and bank
credit markets, ratings assigned by rating agencies and general economic
conditions.
To 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 committed credit facility at Fortis 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. Over the next five years, average
consolidated annual long-term debt maturities and repayments are expected to be
approximately $170 million. The combination of available credit facilities and
low annual debt maturities and repayments provide the Corporation and its
subsidiaries with flexibility in the timing and access to capital markets.
As at June 30, 2009, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.2 billion, of which approximately $1.6
billion was unused. The credit facilities are syndicated almost entirely with
the seven largest Canadian banks with no one bank holding more than 25 per cent
of these facilities.
The following table summarizes the credit facilities of the Corporation and its
subsidiaries.
Total Total
as at as at
Corporate Regulated Fortis June 30, December 31,
($ millions) and Other Utilities Properties 2009 2008
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 645 1,501 13 2,159 2,228
Credit facilities
utilized:
Short-term
borrowings - (170) - (170) (410)
Long-term debt
(Note 8) (144) (128) - (272) (224)
Letters of credit
outstanding (1) (119) (1) (121) (104)
--------------------------------------------------------------------------
Credit facilities
available 500 1,084 12 1,596 1,490
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at June 30, 2009 and December 31, 2008, certain borrowings under the
Corporation's and subsidiaries' credit facilities have been 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.
Corporate and Other
In May 2009, Terasen entered into a $30 million committed revolving credit
facility maturing in May 2011 to replace its $100 million committed revolving
credit facility that matured in May 2009. The terms of the new credit facility
are substantially the same as those of the credit facility it replaced.
Regulated Utilities
On April 30, 2009, FortisBC amended its $150 million unsecured committed
revolving credit facility, including extending the maturity date of the $50
million portion of the facility to May 2012 from May 2011 and extending the
maturity date of the $100 million portion of the facility to May 2010 from May
2009.
In March 2009, Maritime Electric renegotiated its $50 million demand credit
facility and had it converted into a 364-day revolving committed credit
facility.
The following is an analysis of the contractual maturities of the Corporation's
financial liabilities as at June 30, 2009.
Financial Liabilities
Due Due in Due in
within years 2 years 4 Due after
($ millions) 1 year and 3 and 5 5 years Total
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Short-term borrowings 170 - - - 170
Trade and other accounts
payable 636 - - - 636
Natural gas derivatives (1) 110 57 1 - 168
Dividends payable 47 - - - 47
Customer deposits (2) 2 4 1 2 9
Long-term debt, including
current portion (3) 183 335 302 4,573 5,393
Interest obligations on
long-term debt 333 651 615 4,640 6,239
Preference shares, classified
as debt - - 123 197 320
Dividend obligations on
preference shares,
classified as interest
expense 17 33 28 21 99
-------------------------------------------------------------------------
1,498 1,080 1,070 9,433 13,081
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The natural gas derivatives were recorded in accounts payable as at
June 30, 2009.
(2) Customer deposits were recorded in deferred credits as at June 30,
2009.
(3) Excluding deferred financing costs of $37 million
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, its self-sustaining
foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian
dollar exchange rate. The Corporation has effectively decreased the above
exposure through the use of US dollar borrowings at the corporate level. 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 or in a currency pegged to the US dollar. Belize
Electricity's reporting currency is the Belizean dollar, while the reporting
currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and
BECOL is the US dollar. The Belizean dollar is pegged to the US dollar at
BZ$2.00 equals US$1.00.
As at June 30, 2009, all of the Corporation's corporately held US$407 million
long-term debt had been designated as a hedge of a portion of the Corporation's
foreign net investments. As at June 30, 2009, the Corporation had approximately
US$130 million in foreign net investments remaining to be hedged. Foreign
currency exchange rate fluctuations associated with the translation of the
Corporation's corporately held US dollar borrowings that are designated as
hedges are recorded in other comprehensive income and serve to help offset
unrealized foreign currency exchange gains and losses on the foreign net
investments, which are also recorded in other comprehensive income.
TGVI's US dollar payments under a contract for the construction of a liquefied
natural gas storage facility expose TGVI to fluctuations in the US
dollar-to-Canadian dollar exchange rate. TGVI entered into a foreign exchange
forward contract to hedge this exposure. TGVI has 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.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk
associated with short-term borrowings and floating-rate debt. The Corporation
and its subsidiaries may enter into interest rate swap agreements to help reduce
this risk.
During the first half of 2009, Fortis Properties was party to two interest rate
swap agreements that effectively fixed the interest rates on their variable-rate
borrowings.
The Terasen Gas companies and FortisBC have regulatory approval to defer any
increase or decrease in interest expense resulting from fluctuations in interest
rates associated with variable-rate debt for recovery from, or refund to,
customers in future rates.
Commodity Price Risk
The Terasen Gas companies are exposed to commodity price risk associated with
changes in the market price of natural gas. This risk is minimized by entering
into natural gas derivatives that effectively fix the price of natural gas
purchases. The price risk-management strategy of the Terasen Gas companies aims
to improve the likelihood that natural gas prices remain competitive with
electricity rates, temper gas price volatility on customer rates and reduce the
risk of regional price discrepancies. The natural gas derivatives are recorded
on the 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.
20. BUSINESS ACQUISITION
Holiday Inn Select - Windsor
In April 2009, Fortis Properties purchased the Holiday Inn Select in Windsor,
Ontario for an aggregate cash purchase price of approximately $7 million,
including acquisition costs. The acquisition has been accounted for using the
purchase method, whereby the results of operations have been consolidated in the
financial statements of Fortis commencing April 2009.
The purchase price allocation to assets, based on their fair values, was as follows:
($ millions) Total
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Fair value assigned to net assets:
Income producing properties 7
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21. CONTINGENT LIABILITIES AND COMMITMENTS
Contingent liabilities
The Corporation and its subsidiaries are subject to various legal proceedings
and claims associated with ordinary course business operations. Management
believes that the amount of liability, if any, from these actions would not have
a material effect on the Corporation's consolidated financial position or
results of operations. The Corporation's contingent liabilities are consistent
with those disclosed in the Corporation's 2008 annual audited consolidated
financial statements, except for those described below.
Exploits Partnership
The Exploits Partnership operated two non-regulated hydroelectric generation
plants in Newfoundland with a combined capacity of approximately 140 MW. The
Exploits Partnership is owned 51 per cent by Fortis Properties and 49 per cent
by Abitibi. 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 closed in Grand
Falls-Windsor 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, a Crown corporation, as agent for the Government
of Newfoundland and Labrador. The loss of control over cash flows and
operations required Fortis to report its investment in the Exploits Partnership
using the equity method of accounting, effective February 13, 2009. Equity
earnings recognized in the first and second quarters of 2009 are equivalent to
the amounts that would have been recognized under normal hydrology in the
absence of the expropriation. Discussions between Fortis Properties and Nalcor
Energy with respect to expropriation matters are ongoing.
Terasen
On July 16, 2009, Terasen 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 a pipeline rupture in
July 2007. This claim is in its early stages and the amount and outcome of it
is indeterminable at this time.
Commitments
There were no material changes in the nature and amount of the Corporation's
commitments from the commitments disclosed in the Corporation's 2008 annual
audited consolidated financial statements, except for those described below.
During the second quarter, Maritime Electric's take-or-pay contract with New
Brunswick Power ("NB Power"), which includes replacement energy and capacity for
the NB Power Point Lepreau Nuclear Generating Station during its refurbishment
outage, was extended to December 2010. The contract previously expired on March
31, 2009. As at June 30, 2009, the contract totalled approximately $106 million
to December 2010.
Fortis Turks and Caicos has entered into an agreement with a supplier to
purchase two diesel-generating engines with a combined capacity of approximately
17.5 MW for approximately US$12 million (CDN$13 million) for delivery in April
2010 and January 2011.
Belize Electricity has entered into a new 15-year power purchase agreement with
Belize Aquaculture Limited ("BAL"). The agreement provides for the supply of up
to 15 MW of capacity by BAL and expires in April 2024. As at June 30, 2009, the
agreement totalled approximately $258 million to 2024.
Based on the latest completed actuarial valuations, the Corporation's
consolidated defined benefit pension plan funding contributions, including
current service, solvency and special funding amounts, are expected to total
approximately $22 million for 2009, $18 million for 2010, $6 million for 2011,
$3 million for 2012 and $2 million for 2013. These pension funding amounts
include additional obligations determined under December 31, 2008 actuarial
valuations, completed in the first quarter of 2009, associated with defined
benefit pension plans at Newfoundland Power and the Corporation, and under a
December 31, 2007 actuarial valuation of a defined benefit pension plan at
Terasen, also completed in the first quarter of 2009.
22. SUBSEQUENT EVENT
On July 2, 2009, Fortis issued 30-year $200 million 6.51% unsecured debentures,
the net proceeds of which were used to repay in full the indebtedness
outstanding under the Corporation's committed credit facility and for general
corporate purposes.
23. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
classifications, the most significant of which was the reclassification of $48
million from other assets to utility capital assets on the consolidated balance
sheet as at December 31, 2008 related to the net book value of amounts paid to
AESO for transmission capital projects at FortisAlberta.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada. With
total assets approaching $12 billion and annual revenues totalling $3.9 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 three Caribbean countries and a natural gas utility in British
Columbia. Fortis owns and operates non-regulated generation assets across
Canada and in Belize and Upper New York State. It also owns hotels and
commercial real estate across Canada. Fortis Inc. shares are listed on the
Toronto Stock Exchange and trade under the symbol FTS.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2008 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
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