Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) recorded third quarter net
earnings applicable to common shares of $49 million, or $0.31 per common share,
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 ($5.5 million at the Terasen Gas companies and $2
million at Terasen Inc.) associated with the settlement of historical corporate
tax matters at Terasen. Excluding the tax reduction at Terasen, earnings for the
third quarter were $41.5 million, or $0.26 per common share. Year-to-date
earnings were $169 million, or $1.08 per common share, compared to earnings of
$114 million, or $0.86 per common share, for the same period last year.
Year-to-date 2007 financial results only reflected 4 1/2 months of earnings at
Terasen, which was acquired on May 17, 2007.
Excluding the approximate $5.5 million tax reduction, the Terasen Gas companies
incurred a loss of $4.5 million in the third quarter which was comparable to the
same quarter last year. Due to seasonality of the business, virtually all of the
annual earnings of the Terasen Gas companies are generated in the first and
fourth quarters.
Earnings at Canadian Regulated Electric Utilities were $38 million for the third
quarter, $10 million higher than earnings for the same quarter last year. The
growth in earnings was driven primarily by the favourable impact of a shift in
the quarterly distribution of annual purchased power expense at Newfoundland
Power, which increased earnings during the third quarter of 2008 by
approximately $5.5 million, lower energy supply costs at FortisBC and higher
corporate tax recoveries at FortisAlberta.
Newfoundland Power's annual earnings are not expected to be impacted by the
shift in the quarterly distribution of annual purchased power expense; however,
earnings are expected to be lower in the first and fourth quarters and higher in
the second and third quarters compared to the same periods last year.
In September, FortisBC filed its 2009 rate application requesting a general rate
increase, effective January 1, 2009, reflecting the impact of ongoing investment
in infrastructure and increasing power purchases driven by customer growth and
increased electricity demand. In October, Maritime Electric filed for a basic
rate increase, effective April 1, 2009, reflecting an increase in the amount of
energy-related costs to be collected from customers through the basic rate
component of customer billings.
Earnings at Caribbean Regulated Electric Utilities were $7 million for the third
quarter compared to $10 million for the same quarter last year. The decrease
related to the 3.25 per cent reduction in basic electricity rates at Caribbean
Utilities, effective January 1, 2008; the lower allowed rate of return on rate
base assets ("ROA") at Belize Electricity; and a loss of revenue at Fortis Turks
and Caicos due to the impact of Hurricane Ike, partially offset by overall
growth in electricity sales.
Belize Electricity's targeted allowed ROA was reduced to 10 per cent from 12 per
cent as a result of the regulator's Final Decision on the utility's 2008/2009
Rate Application. On July 25, 2008, Belize Electricity filed applications with
the Supreme Court of Belize for leave to apply for judicial review of 2008
amended bylaws upon which the Final Decision was premised, and appeal of the
Final Decision. Leave was granted on October 3, 2008. It is expected that the
judicial review will be heard in late 2008.
In September, Hurricane Ike struck the Turks and Caicos Islands causing damage
to the distribution system of Fortis Turks and Caicos. The Category 4 hurricane
did not cause any significant damage to the utility's generating facilities. By
late October, electricity service had been restored to all customers of Fortis
Turks and Caicos that were ready to receive service. Earnings for the third
quarter at Fortis Turks and Caicos were reduced by approximately $1 million due
to a loss of revenue as a result of damage caused by Hurricane Ike. The utility
has business interruption insurance with a 30-day deductible period and is in
the preliminary stage of determining its business interruption insurance claim.
A large portion of the costs associated with re-connecting customers and
restoring electricity service were capital in nature and, therefore, did not
impact earnings.
Earnings at Non-Regulated Fortis Generation were $9 million for the third
quarter, up $4 million from the same quarter last year, mainly due to increased
hydroelectric production in Belize and upper New York State as a result of
higher rainfall. Hydroelectric production in Belize was 22 per cent higher year
to date compared to the same period last year. At the end of October, the
Chalillo reservoir in Belize was at its full supply level.
Earnings at Fortis Properties were $9 million for the third quarter compared to
$8 million for the same quarter last year. The increase was due to improved
performance at the Hospitality and Real Estate Divisions, including
contributions from the Delta Regina which was acquired on August 1, 2007.
Corporate and other expenses were $15 million for the third quarter compared to
$16 million for the same quarter last year. The decrease was primarily driven by
the approximate $2 million favourable impact of the tax settlement at Terasen
Inc.
Year to date, cash flow from operating activities was $449 million compared to
$221 million for the same period last year, primarily due to the contributions
from the Terasen Gas companies for nine months in 2008 compared to 4 1/2 months
in 2007.
Consolidated capital expenditures, before customer contributions, were $623
million year to date and are expected to exceed $900 million in 2008. The
consolidated capital program is being driven by the utilities in western Canada
and regulated and non-regulated electric utility operations in the Caribbean.
As at September 30, 2008, Fortis had consolidated credit facilities of $2.2
billion, of which $1.5 billion was unused. Over the next five years, average
annual long-term debt maturities are expected to be approximately $180 million.
To the end of October, Fortis and its utilities have raised almost $900 million
in preferred equity and 30-year debt in 2008, including $230 million 5.25%
Five-Year Fixed Rate Reset First Preference Shares, Series G, at Fortis Inc.,
$250 million 5.80% debentures at Terasen Gas Inc., $250 million 6.05% debentures
at Terasen Gas (Vancouver Island) Inc., $100 million 5.85% debentures at
FortisAlberta, and $60 million 6.05% bonds at Maritime Electric.
In August, Caribbean Utilities completed a Rights Offering, raising gross
proceeds of approximately US$28 million of which Fortis contributed US$24
million as a result of its participation in the Rights Offering. The proceeds
are being used to repay credit facility borrowings and to finance capital
expenditures.
In October, Standard & Poor's removed Fortis from the S&P/TSX Completion and
Equity Completion indices and placed Fortis in the S&P/TSX 60, 60 Capped and
Equity 60 indices.
"Our utilities remain focused on executing their remaining capital projects for
2008. Over the next five years, our consolidated capital program is expected to
surpass $4.5 billion, substantially all of which will be funded at the
subsidiary level. This capital investment, which will mainly be in western
Canada and the Caribbean, will add value for our customers and shareholders and
fortify our position as a leading owner of energy infrastructure in Canada,"
says Stan Marshall, President and Chief Executive Officer, Fortis Inc.
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2008
Dated October 31, 2008
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 nine months ended September 30,
2008 and the Management Discussion and Analysis ("MD&A") and audited
consolidated financial statements for the year ended December 31, 2007 included
in the Corporation's 2007 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 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", "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: that cash required to complete the
consolidated capital expenditure program and to finance acquisitions is expected
to be derived from a combination of borrowings under credit facilities and the
issuance of common shares, preference shares and long-term debt; the
Corporation's consolidated forecasted gross capital expenditures for 2008 and in
total over the next five years and the Corporation's belief that its capital
program should drive growth in earnings; the expected average annual long-term
debt maturities over the next five years; the expectation that counterparties to
the Terasen Gas companies' derivative financial instruments will continue to
meet their obligations; the expected timing of receipt of regulatory rate
decisions; the expected timing of the judicial review of 2008 amended bylaws
relating to Belize Electricity; and the expected impact of Hurricane Ike on
fourth quarter 2008 revenue of Fortis Turks and Caicos. The forecasts and
projections that make up the forward-looking information are based on
assumptions which include, but are not limited to: the receipt of applicable
regulatory approvals and requested rate orders; no significant operational
disruptions or environmental liability due to a catastrophic event or
environmental upset caused by severe weather, other acts of nature or other
major events; the Corporation's ability to maintain its gas and electricity
systems to ensure their continued performance; the competitiveness of natural
gas pricing when compared with electricity and other alternative sources of
energy; the availability of natural gas supply; favourable economic conditions;
the level of interest rates; the ability to hedge certain risks; no counterparty
defaults; access to capital; maintenance of adequate insurance coverage; the
ability to obtain licences and permits; the level of energy prices; retention of
existing service areas; 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. The factors which could
cause results or events to differ from current expectations include, but are not
limited to: regulation; operating and maintenance risks; natural gas prices and
supply; economic conditions; weather and seasonality; interest rates; changes in
tax legislation; derivative financial instruments and hedging; counterparty
risk; risks related to Terasen Gas (Vancouver Island) Inc.; capital resources;
environment; insurance; licences and permits; energy prices and the cessation of
the Niagara Exchange Agreement; loss of service area; First Nations Lands;
labour relations; human resources; and liquidity risk. For additional
information with respect to the Corporation's risk factors, reference should be
made to the Corporation's continuous disclosure materials filed from time to
time with Canadian securities regulatory authorities and to the heading
"Business Risk Management" in the MD&A for the three and nine months ended
September 30, 2008 and for the year ended December 31, 2007.
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 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 2008, the Corporation's
electricity distribution systems met a combined peak electricity demand of
approximately 5,600 megawatts ("MW") and its gas distribution systems met a peak
day demand of 1,313 terajoules ("TJ"). For additional information on the
Corporation's business segments, refer to Note 1 to the Corporation's interim
unaudited consolidated financial statements for the three and nine months ended
September 30, 2008.
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 third quarter and year-to-date periods
ended September 30, 2008 and September 30, 2007, are provided in the table
below.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions, except
earnings per common
share and common shares
outstanding) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Revenue 727 651 76 2,721 1,700 1,021
-------------------------------------------------------------------------
Cash flow from operating
activities 17 59 (42) 449 221 228
-------------------------------------------------------------------------
Net earnings applicable
to common shares 49 31 18 169 114 55
-------------------------------------------------------------------------
Basic earnings per
common share ($) 0.31 0.20 0.11 1.08 0.86 0.22
-------------------------------------------------------------------------
Diluted earnings per
common share ($) 0.31 0.20 0.11 1.06 0.79 0.27
-------------------------------------------------------------------------
Weighted average number
of common shares
outstanding (millions) 157.2 154.5 2.7 156.9 131.6 25.3
-------------------------------------------------------------------------
Segmented Net Earnings
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Regulated Gas
Utilities - Canadian
-------------------------------------------------------------------------
Terasen Gas
Companies (1) 1 (4) 5 71 (3) 74
-------------------------------------------------------------------------
Regulated Electric
Utilities - Canadian
-------------------------------------------------------------------------
FortisAlberta 17 15 2 35 42 (7)
-------------------------------------------------------------------------
FortisBC (2) 8 6 2 27 24 3
-------------------------------------------------------------------------
Newfoundland Power 8 2 6 24 21 3
-------------------------------------------------------------------------
Other Canadian (3) 5 5 - 11 13 (2)
-------------------------------------------------------------------------
38 28 10 97 100 (3)
-------------------------------------------------------------------------
Regulated Electric
Utilities
- Caribbean (4) 7 10 (3) 9 22 (13)
-------------------------------------------------------------------------
Non-Regulated - Fortis
Generation (5) 9 5 4 22 17 5
-------------------------------------------------------------------------
Non-Regulated - Fortis
Properties (6) 9 8 1 19 16 3
-------------------------------------------------------------------------
Corporate and Other (7) (15) (16) 1 (49) (38) (11)
-------------------------------------------------------------------------
Net Earnings Applicable
to Common Shares 49 31 18 169 114 55
-------------------------------------------------------------------------
(1) Comprised of Terasen Gas Inc. ("TGI"), Terasen Gas (Vancouver Island)
Inc. ("TGVI") and Terasen Gas (Whistler) Inc. ("TGWI"). Financial
results are reported from May 17, 2007, the date of acquisition.
(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 57 per cent
controlling interest; and wholly owned Fortis Turks and Caicos.
Caribbean Utilities had an April 30 fiscal year end whereby, 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. Caribbean Utilities has changed its fiscal year
end to December 31 which will result in the Corporation consolidating
five months of financial results of Caribbean Utilities during the
fourth quarter of 2008. Going forward, this will eliminate the
previous two-month lag in consolidating Caribbean Utilities' financial
results.
(5) Includes the operations of non-regulated generation assets in Belize,
Ontario, central Newfoundland, British Columbia and upper New York
State, with a combined generating capacity of 195 MW, mainly
hydroelectric.
(6) Includes 19 hotels with more than 3,500 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 and, from May 17, 2007, the 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.
("TES").
-------------------------------------------------------------------------
-------------------------------------------------------------------------
SEGMENTED RESULTS OF OPERATIONS
REGULATED GAS UTILITIES - CANADIAN
Terasen Gas Companies
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Terasen Gas Companies
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007(1) Variance 2008 2007(1) Variance
-------------------------------------------------------------------------
Gas Volumes (TJ) 30,798 31,441 (643) 154,306 49,185 105,121
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 271 227 44 1,296 357 939
-------------------------------------------------------------------------
Energy Supply Costs 157 118 39 850 191 659
-------------------------------------------------------------------------
Operating Expenses 59 56 3 182 84 98
-------------------------------------------------------------------------
Amortization 24 23 1 73 35 38
-------------------------------------------------------------------------
Finance Charges 33 33 - 96 48 48
-------------------------------------------------------------------------
Corporate Taxes
(Recoveries) (3) 1 (4) 24 2 22
-------------------------------------------------------------------------
Earnings (Loss) 1 (4) 5 71 (3) 74
-------------------------------------------------------------------------
(1) Financial results are reported from May 17, 2007, the date of
acquisition.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On May 17, 2007, Fortis acquired all of the issued and outstanding common shares
of Terasen. Terasen owns and operates a gas distribution business carried on by
TGI, TGVI and TGWI, collectively referred to as the Terasen Gas companies, and
is the principal distributor of natural gas in British Columbia.
Gas volumes: Gas volumes at the Terasen Gas companies decreased 643 TJ, or 2.0
per cent, quarter over quarter. The decrease was primarily due to lower
transportation volumes to customers sourcing their own gas supplies, partially
offset by higher sales volumes to residential customers as a result of increased
consumption due to cooler weather compared to the same quarter last year and
customer growth, and increased sales volumes to customers under fixed price
contracts. Gas volumes were 154,306 TJ year to date, up 2,437 TJ, or 1.6 per
cent, from 151,869 TJ reported by the Terasen Gas companies for the full
year-to-date period last year. The increase was driven by higher sales volumes
to residential customers as a result of increased consumption due to cooler
weather compared to the same period last year and customer growth, and increased
sales volumes to customers under fixed price contracts. The increase was
partially offset by lower transportation volumes to customers sourcing their own
gas supplies.
Changes in consumption levels and energy supply costs, from those forecasted to
set gas distribution rates, do not materially impact earnings as a result of the
operation of British Columbia Utilities Commission ("BCUC")-approved regulatory
deferral mechanisms.
During the third quarter of 2008, net customer additions at TGI and TGVI
totalled 2,244, bringing the total customer count to 924,204 at September 30,
2008. Year-to-date 2008, net customer additions of 5,573, compared to net
customer additions of 6,323 for the same period last year, were in line with
expectations. Favourable economic conditions and housing activity in British
Columbia continue to positively impact customer growth in the region.
Revenue: Revenue was $44 million higher quarter over quarter mainly due to: (i)
increased residential customer consumption; (ii) higher gas commodity costs
charged to customers; and (iii) an increase in gas distribution rates, effective
January 1, 2008, associated with an increase in the 2008 allowed rate of return
on common shareholder's equity ("ROE") for TGI and TGVI to 8.62 per cent and
9.32 per cent, respectively, from 8.37 per cent and 9.07 per cent, respectively.
Revenue was approximately $1.3 billion year to date compared to $357 million for
the partial year-to-date period last year. In addition to the impact of revenue
contribution for the full year-to-date period in 2008, revenue also increased
period over period due to the same factors as described above for the quarter.
Earnings: Earnings were $5 million higher quarter over quarter, driven by a tax
reduction associated with the settlement of historical corporate tax matters.
During the third quarter, Terasen reached a settlement with Revenu Quebec and
Canada Revenue Agency related to amounts owing as a result of amended Quebec tax
legislation. The legislation was passed in 2006 for the purpose of challenging
certain inter-provincial Canadian tax structures. As a result of the
settlement, the Terasen Gas companies recorded an approximate $5.5 million tax
reduction in the third quarter of 2008. Excluding the tax reduction, the
Terasen Gas companies incurred a loss of approximately $4.5 million in the third
quarter, which is comparable to the same quarter last year. Seasonality
materially impacts the earnings of the Terasen Gas companies as a major portion
of the gas distributed is used for space heating. Virtually all of the annual
earnings of the Terasen Gas companies are generated in the first and fourth
quarters. Quarter over quarter, the impact of the increase in gas distribution
rates, effective January 1, 2008, customer growth and a lower effective
corporate tax rate was offset by higher operating expenses driven by increased
labour costs and increased amortization costs associated with the continued
investment in capital assets.
Earnings were $71 million year to date compared to a loss of $3 million for the
partial year-to-date period last year. In addition to earnings' contribution
for the full year-to-date period in 2008 and the impact of the tax reduction
described above, earnings year to date were favourably impacted by the increase
in gas distribution rates, effective January 1, 2008, customer growth and a
lower effective corporate tax rate. The increase was partially offset by higher
operating expenses and amortization costs, for the same reasons as described
above for the quarter, in addition to higher finance charges reflective of
higher borrowing rates and increased credit facility borrowings.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Terasen Gas companies, refer to "Regulatory
Highlights".
REGULATED ELECTRIC UTILITIES - CANADIAN
FortisAlberta
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FortisAlberta
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Energy Deliveries
(GWh) 3,748 3,781 (33) 11,654 11,376 278
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 74 70 4 222 202 20
-------------------------------------------------------------------------
Operating Expenses 31 31 - 96 90 6
-------------------------------------------------------------------------
Amortization 22 19 3 63 56 7
-------------------------------------------------------------------------
Finance Charges 10 8 2 30 26 4
-------------------------------------------------------------------------
Corporate Tax
Recoveries (6) (3) (3) (2) (12) 10
-------------------------------------------------------------------------
Earnings 17 15 2 35 42 (7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Deliveries: Energy deliveries at FortisAlberta decreased 33 gigawatt
hours ("GWh"), or 0.9 per cent, quarter over quarter. Lower average consumption
quarter over quarter more than offset the impact of customer growth. Average
consumption during the third quarter last year was high due to a
hotter-than-normal July. Energy deliveries increased 278 GWh, or 2.4 per cent,
year to date compared to the same period last year, mainly due to customer
growth. Year-to-date 2008, the number of customers at FortisAlberta had
increased by approximately 8,800 to 456,800. As a significant portion of the
Company's distribution revenue is derived from fixed or largely fixed billing
determinants, changes in energy deliveries are not directly correlated with
changes in revenue.
Revenue: Revenue was $4 million higher quarter over quarter and $20 million
higher year to date compared to the same period last year. The increases were
mainly due to a 6.8 per cent increase in customer distribution rates, effective
January 1, 2008; the impact of customer and load growth; the accrual of the
impact for collection in future customer distribution rates of the increase in
the 2008 allowed ROE to 8.75 per cent from 8.51 per cent, effective January 1,
2008; and increased franchise fee revenue. The increases were partially offset
by lower net transmission and miscellaneous revenue.
Earnings: Earnings were $2 million higher quarter over quarter, driven by
increased future income tax recoveries primarily associated with the
regulator-approved Alberta Electric System Operator ("AESO") charges deferral
account. Quarter over quarter, the impact of the increase in customer
distribution rates, customer and load growth, and a higher allowed ROE was more
than offset by increased amortization costs associated with continued investment
in capital assets and higher amortization rates provided for in the 2008/2009
Negotiated Settlement Agreement ("NSA"), and increased finance charges due to
higher debt levels in support of the Company's significant capital expenditure
program.
Earnings were $7 million lower year to date compared to the same period last
year, driven by lower future income tax recoveries primarily associated with the
regulator-approved AESO charges deferral account. Additionally, the impact of
the increase in customer distribution rates, customer and load growth, and a
higher allowed ROE was partially offset by: (i) higher operating expenses due to
increased contracted manpower costs, higher labour and employee-benefit costs
associated with increased salaries and number of employees, and higher general
operating expenses; and (ii) increased amortization costs and finance charges
for the reasons as described above for the quarter.
FortisAlberta's AESO charges deferral account captures variances between amounts
charged by the AESO to FortisAlberta for transmission tariffs and amounts
collected by FortisAlberta from customers through the transmission tariff
component of basic customer rates. Subject to regulatory approval, amounts
charged by the AESO in excess of amounts collected from customers are deferred
as a regulatory asset for future recovery from customers and amounts collected
from customers in excess of amounts charged are deferred as a regulatory
liability for future refund to customers. Generally, there is a two-year lag
between the deferral of amounts in the AESO charges deferral account and when
they are collected from, or refunded to, customers in rates.
FortisAlberta records income taxes on the cash taxes payable method, as approved
by its regulator, except for certain deferral accounts, including the AESO
charges deferral account, whereby income taxes are recorded using the liability
method. During the third quarter of 2008, FortisAlberta identified that taxable
income from operations, before considering impacts associated with the AESO
charges deferral account, could be fully offset by utilizing capital cost
allowance deductions. Then, by applying the tax deductions related to
transmission tariff payments made to the AESO, a tax loss carryforward could be
created and a future income tax recovery could be recorded. Under the liability
method of recording income taxes, a future income tax asset associated with the
tax loss carryforward is not recorded unless there is certainty of recovery.
The transmission tariff payments made to the AESO are recoverable from customers
in the future; therefore, a future income tax asset has been recorded in the
third quarter of 2008 which has been offset against FortisAlberta's long-term
future income tax liability.
Prior to the third quarter of 2008, FortisAlberta was not deducting transmission
tariff payments made to the AESO to create tax loss carryforwards and was not
recording the associated future income tax recovery. This, in effect, resulted
in a two-year lag of recording the future income tax impacts between the
payments of transmission tariff amounts to the AESO and the timing of their
collection from customers. Going forward, fluctuations in corporate income
taxes associated with the operation of the AESO charges deferral account are not
expected to occur.
FortisAlberta recorded a $4.5 million recovery of future income taxes during the
third quarter of 2008 that were previously expensed during the first half of
2008. For the third quarter and year-to-date period in 2007, future income tax
recoveries of approximately $3 million and $10 million, respectively, were
recorded primarily due to the expedited collection of amounts deferred to the
AESO charges deferral account. In September 2007 and December 2007, the 2006
deferred AESO charges receivable balance of $28 million and approximately $38
million of the 2007 deferred AESO charges receivable balance, respectively, were
sold to a Canadian chartered bank and, as a result, the proceeds were recognized
in 2007.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisAlberta, refer to "Regulatory Highlights".
FortisBC
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FortisBC
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Electricity Sales
(GWh) 697 703 (6) 2,245 2,252 (7)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 52 52 - 171 167 4
-------------------------------------------------------------------------
Energy Supply Costs 12 15 (3) 45 48 (3)
-------------------------------------------------------------------------
Operating Expenses 16 16 - 49 49 -
-------------------------------------------------------------------------
Amortization 8 7 1 25 23 2
-------------------------------------------------------------------------
Finance Charges 7 7 - 21 19 2
-------------------------------------------------------------------------
Corporate Taxes 1 1 - 4 4 -
-------------------------------------------------------------------------
Earnings 8 6 2 27 24 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at FortisBC decreased 6 GWh, or 0.9 per
cent, quarter over quarter and decreased 7 GWh, or 0.3 per cent, year to date
compared to the same period last year. The impact of reduced industrial
customer loads, as a result of a general slowdown in the forestry sector, was
partially offset by residential, general service and wholesale customer growth,
primarily in the Okanagan region.
Revenue: Revenue was comparable quarter over quarter. The favourable impact of:
(i) a 2.9 per cent increase in electricity rates, effective January 1, 2008,
which included the impact of an increase in the 2008 allowed ROE to 9.02 per
cent from 8.77 per cent; (ii) a 0.8 per cent increase in electricity rates,
effective May 1, 2008, as a result of the flow through to customers of increased
purchased power costs from BC Hydro; and (iii) a shift in sales mix from
lower-rate customer classes to higher-rate customer classes was offset by: (i)
lower revenue contributions from non-regulated operating, maintenance and
management services; (ii) decreased electricity sales; and (iii) increased
performance-based rate setting ("PBR") incentive adjustments owing to customers,
which reduced revenue.
Revenue was $4 million higher year to date compared to the same period last
year, driven by the increases in electricity rates and the shift in sales mix,
partially offset by the same factors as described above for the quarter.
Earnings: FortisBC's earnings were $2 million higher quarter over quarter. The
increase was mainly due to decreased energy supply costs, partially offset by
higher amortization costs reflective of the Company's significant capital
expenditure program. The decrease in energy supply costs was driven by a higher
proportion of energy generated from Company-owned hydroelectric generating
plants compared to purchased power over the reporting periods, decreased
electricity sales and lower average market power purchase prices, partially
offset by higher prices charged by BC Hydro that were flowed through to
customers in rates.
Earnings were $3 million higher year to date compared to the same period last
year. The increase was primarily due to the 2.9 per cent increase in
electricity rates and decreased energy supply costs, partially offset by higher
amortization costs and finance charges related to the Company's significant
capital expenditure program. Energy supply costs decreased for the reasons as
described above for the quarter combined with the impact of the receipt of $0.6
million in insurance proceeds during the second quarter of 2008 associated with
a turbine generator failure in 2006.
Operating expenses were comparable quarter over quarter and year to date
compared to the same period last year. The impact of the timing in 2008 of
certain operating and maintenance projects combined with higher labour costs and
general inflationary cost increases was offset by lower operating expenses
associated with non-regulated operating, maintenance and management services.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to FortisBC, refer to "Regulatory Highlights".
Newfoundland Power
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Newfoundland Power
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Electricity Sales
(GWh) 897 874 23 3,796 3,709 87
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 94 90 4 378 359 19
-------------------------------------------------------------------------
Energy Supply Costs 51 59 (8) 243 239 4
-------------------------------------------------------------------------
Operating Expenses 11 12 (1) 38 39 (1)
-------------------------------------------------------------------------
Amortization 11 6 5 33 25 8
-------------------------------------------------------------------------
Finance Charges 8 10 (2) 25 26 (1)
-------------------------------------------------------------------------
Corporate Taxes 5 1 4 15 9 6
-------------------------------------------------------------------------
Earnings 8 2 6 24 21 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at Newfoundland Power increased 23 GWh, or
2.6 per cent, quarter over quarter and increased 87 GWh, or 2.3 per cent, year
to date compared to the same period last year. The increases were largely due
to the combined impact of customer growth and higher average consumption.
Revenue: Revenue was $4 million higher quarter over quarter and $19 million
higher year to date compared to the same period last year. The increases were
driven by an average increase in customer rates of 2.8 per cent, effective
January 1, 2008, which included the impact of an increase in the 2008 allowed
ROE to 8.95 per cent from 8.60 per cent, and electricity sales growth. The
increase in revenue also reflected higher amortization of regulatory liabilities
in accordance with prescribed regulatory orders.
Earnings: Newfoundland Power's earnings were $6 million higher quarter over
quarter, reflecting a shift in the quarterly distribution of annual purchased
power expense which increased earnings by approximately $5.5 million during the
third quarter of 2008. Under the regulated rate structure, annual purchased
power expense per kilowatt hour ("kWh") is higher in the winter months and lower
in the summer months. During 2007, Newfoundland Power estimated and recognized
monthly purchased power expense based on forecast annual average cost per kWh.
Differences between the estimated monthly purchased power expense and that based
on the actual cost per kWh were adjusted to a regulatory reserve that was
discontinued for use effective January 1, 2008. Monthly purchased power expense
is now being recorded at actual cost per kWh. As a result of this change,
earnings in 2008 are expected to be lower in the first and fourth quarters and
higher in the second and third quarters compared to the same periods in 2007.
Annual earnings will not be impacted by the shift in the quarterly distribution
of annual purchased power expense. Excluding the approximate $5.5 million
favourable impact of the shift in the quarterly distribution of annual purchased
power expense, as described above, earnings were comparable quarter over
quarter.
Newfoundland Power's earnings were $3 million higher year to date compared to
the same period last year, reflecting the shift in the quarterly distribution of
annual purchased power expense which increased year-to-date earnings by
approximately $2 million.
Amortization costs are allocated quarterly based on gross margin. Amortization
costs increased due to the shift in the quarterly distribution of annual
purchased power expense and the regulator-approved recovery of previously
deferred amortization costs in customer rates, effective January 1, 2008.
Corporate tax expense increased quarter over quarter and year to date compared
to the same period last year as a result of higher earnings before corporate
taxes, combined with higher effective corporate income tax rates. Higher
effective corporate income tax rates were driven by decreased deductions taken
for tax purposes compared to accounting purposes.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Newfoundland Power, refer to "Regulatory
Highlights".
Other Canadian Electric Utilities
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Other Canadian Electric Utilities (1)
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Electricity
Sales (GWh) 532 537 (5) 1,639 1,655 (16)
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 66 63 3 197 198 (1)
-------------------------------------------------------------------------
Energy Supply Costs 44 41 3 133 132 1
-------------------------------------------------------------------------
Operating Expenses 7 7 - 21 21 -
-------------------------------------------------------------------------
Amortization 4 4 - 13 12 1
-------------------------------------------------------------------------
Finance Charges 4 4 - 13 13 -
-------------------------------------------------------------------------
Corporate Taxes 2 2 - 6 7 (1)
-------------------------------------------------------------------------
Earnings 5 5 - 11 13 (2)
-------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Electricity sales at Other Canadian Electric Utilities
decreased 5 GWh, or 0.9 per cent, quarter over quarter, driven by lower average
consumption in Ontario, partially offset by the impact of an increase in the
number of residential customers on Prince Edward Island. Electricity sales
decreased 16 GWh, or 1.0 per cent, year to date compared to the same period last
year, driven by lower average consumption in Ontario, the loss of a major
industrial customer in Ontario in the first quarter of 2007, and the shutdown of
operations of another industrial customer in Ontario from May 2007.
Revenue: Revenue was $3 million higher quarter over quarter, driven by a 1.8 per
cent increase in basic electricity rates at Maritime Electric, effective April
1, 2008; an average 1.1 per cent increase in basic electricity distribution
rates at FortisOntario, effective May 1, 2008; and the flow through to customers
of higher energy supply costs at FortisOntario. The increase was partially
offset by the impact of lower electricity sales.
Year to date, revenue was $197 million compared to $198 million for the same
period last year. The decrease was due to the impact of lower electricity sales
and the repayment, during the second quarter of 2008, of an approximate $3
million refund that FortisOntario had received during the fourth quarter of
2007, partially offset by the increase in basic electricity rates, as described
above for the quarter, and the flow through of higher energy supply costs at
FortisOntario. In April 2008, the US Federal Energy Regulatory Commission
("FERC") issued an order stating that the one-time refund of approximately $3
million ($2 million after-tax) received by FortisOntario in December 2007 from
Niagara Mohawk Power Corporation ("NIMO"), associated with cross-border
transmission interconnection agreements, should not have been originally ordered
as FERC does not have jurisdiction over the interconnection agreements in
question and, therefore, did not have jurisdiction to order the refund. In May
2008, FortisOntario repaid the refunded amounts to NIMO.
Earnings: Earnings were comparable quarter over quarter and $2 million lower
year to date compared to the same period last year. Excluding the one-time $2
million after-tax repayment during the second quarter of 2008 by FortisOntario
of the refund described above, earnings were comparable year to date compared to
the same period last year. The impact of increased basic electricity rates was
offset largely by the impact of decreased electricity sales.
In October 2008, FortisOntario entered into a definitive agreement to acquire a
10 per cent minority interest in Grimsby Power Inc.'s electricity distribution
business for a cash payment of approximately $1.1 million plus the provision of
services to migrate Grimsby Power Inc.'s customer information system with
FortisOntario's system. Grimsby Power Inc. serves approximately 10,000
customers in a service territory that is in close proximity to FortisOntario's
operations in Fort Erie. The closing of this transaction is subject to the
receipt of regulatory approvals.
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to Maritime Electric and FortisOntario, refer to
"Regulatory Highlights".
REGULATED ELECTRIC UTILITIES - CARIBBEAN
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Regulated Electric Utilities - Caribbean (1)
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.04 1.04 - 1.02 1.10 (0.08)
-------------------------------------------------------------------------
Electricity
Sales (GWh) 304 283 21 838 782 56
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 96 80 16 249 231 18
-------------------------------------------------------------------------
Energy Supply Costs 60 42 18 164(3) 127 37
-------------------------------------------------------------------------
Operating Expenses 12 11 1 35 39(4) (4)
-------------------------------------------------------------------------
Amortization 8 7 1 23 21 2
-------------------------------------------------------------------------
Finance Charges 4 4 - 11 11 -
-------------------------------------------------------------------------
Corporate Taxes 1 - 1 1 1 -
-------------------------------------------------------------------------
Non-Controlling Interest 4 6 (2) 6 10 (4)
-------------------------------------------------------------------------
Earnings 7 10 (3) 9 22 (13)
-------------------------------------------------------------------------
(1) Includes Belize Electricity, Caribbean Utilities and Fortis Turks and
Caicos
(2) The reporting currency of Belize Electricity is the Belizean dollar
which is pegged to the US dollar at BZ$2.00 equals US$1.00. The
reporting currency of Caribbean Utilities and Fortis Turks and Caicos
is the US dollar. The Cayman Islands dollar is pegged to the US dollar
at CI$1.00 equals US$1.20.
(3) 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 ("PUC") in Belize in June
2008.
(4) Operating expenses during the first quarter of 2007 included a $4.4
million (US$3.7 million) charge on the disposal of steam-turbine assets
at Caribbean Utilities.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Electricity Sales: Regulated Electric Utilities - Caribbean electricity sales
increased 21 GWh, or 7.4 per cent, quarter over quarter and increased 56 GWh, or
7.2 per cent, year to date compared to the same period last year. The increases
were primarily due to customer growth, higher average usage associated with
increased air conditioning load at Caribbean Utilities, and the impact of
general economic growth. The increase was tempered by the loss of electricity
sales at Fortis Turks and Caicos as a result of Hurricane Ike, a Category 4
hurricane which struck the Turks and Caicos Islands in early September 2008.
Despite the impact of Hurricane Ike, electricity sales at Fortis Turks and
Caicos increased approximately 4 per cent quarter over quarter and 12 per cent
year to date compared to the same period last year. Revenue losses, as a result
of damage caused by Hurricane Ike, are estimated at approximately $1 million for
each of the third and fourth quarters of 2008. Fortis Turks and Caicos has
business interruption insurance coverage with a 30-day deductible period and is
in the preliminary stage of determining its business interruption insurance
claim. A large portion of the costs of reconnecting customers and restoring
electricity service were capital in nature and, therefore, did not impact
earnings. By late October, electricity service had been restored to all
customers of Fortis Turks and Caicos that were ready to receive service who were
impacted by Hurricane Ike.
Annual electricity sales growth at Regulated Electric Utilities - Caribbean
segment for 2008 is expected to be between 6 per cent and 7 per cent. While
still strong, electricity sales growth at Caribbean Utilities and Fortis Turks
and Caicos is expected to be slightly lower than originally forecasted,
reflecting a weakening US economy that may negatively affect the tourism
industry, and the impact of Hurricane Ike including the delayed re-opening for
the fall tourist season of several large hotels on the Turks and Caicos Islands.
Revenue: Revenue increased $16 million quarter over quarter and $18 million year
to date compared to the same period last year. Excluding the unfavourable
impact of foreign exchange associated with the translation of foreign
currency-denominated revenue due to the strengthening of the Canadian dollar
against the US dollar year-to-date September 2008 compared to the same period
last year, revenue increased approximately $38 million year to date compared to
the same period last year.
Excluding the impact of foreign currency translation, factors increasing revenue
were: (i) strong electricity sales growth; (ii) the full flow through of higher
fuel and oil costs to customers at Caribbean Utilities under the terms of the
Company's new transmission and distribution ("T&D") licence; and (iii) an
increase in the cost of power component of the average electricity rate at
Belize Electricity, effective July 1, 2008. Partially offsetting the above
factors were: (i) a 3.25 per cent reduction in basic electricity rates and the
elimination of the hurricane cost recovery surcharge ("CRS") at Caribbean
Utilities, effective January 1, 2008, under the terms of the Company's new T&D
licence; (ii) a decrease in the value-added ("VAD") component of the average
electricity rate at Belize Electricity, effective July 1, 2008; and (iii)
revenue losses due to Hurricane Ike.
Earnings: Earnings' contribution was $3 million lower quarter over quarter,
mainly due to: (i) a reduction in the VAD component of the average electricity
rate at Belize Electricity; (ii) the 3.25 per cent reduction in basic
electricity rates and the elimination of the CRS at Caribbean Utilities; (iii)
higher amortization costs; (iv) increased operating expenses; and (v) revenue
losses due to Hurricane Ike. The decrease was partially offset by the impact of
electricity sales growth.
Earnings' contribution was $13 million lower year to date compared to the same
period last year. Earnings' contribution during the second quarter of 2008 was
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 at Belize Electricity. The $18 million (BZ$36 million) charge was the
result of the PUC's decision on Belize Electricity's 2008/2009 rate application.
Also, earnings' contribution year-to-date 2007 was reduced by approximately $2
million as a result of the Corporation's share of a charge on the disposal of
steam-turbine assets at Caribbean Utilities.
Excluding the one-time items in 2008 and 2007, as described above, and an
approximate $2 million unfavourable impact of foreign currency translation,
earnings' contribution year to date was comparable to the same period last year.
Electricity sales growth and the favourable impact on energy supply costs
associated with the movement in deferred fuel costs at Caribbean Utilities were
offset by: (i) the impact of the 3.25 per cent reduction in basic electricity
rates and the elimination of the CRS at Caribbean Utilities; (ii) the reduction
in the VAD component of the average electricity rate at Belize Electricity;
(iii) higher amortization costs; (iv) increased operating expenses; and (v)
revenue losses due to Hurricane Ike. The movement in deferred fuel costs at
Caribbean Utilities was the result of a change in the basis for calculating
those costs under Caribbean Utilities' new T&D licence.
Excluding the impact of foreign currency translation and the charge on the
disposal of steam-turbine assets during the first quarter of 2007, operating
expenses increased quarter over quarter and year to date compared to the same
period last year, reflecting the impact of hiring additional employees at Fortis
Turks and Caicos and increased general and administrative expenses.
Amortization costs increased as a result of continued investment in capital
assets.
In addition to the $18 million charge described above, Belize Electricity's
target allowed rate of return on rate base assets ("ROA") has been reduced to 10
per cent from 12 per cent, which is reflected through a reduction in the VAD
component of the average electricity rate, effective July 1, 2008.
In August 2008, Caribbean Utilities completed a Rights Offering, raising gross
proceeds of approximately US$28 million. The proceeds are being used to repay
credit facility borrowings and to finance capital expenditures. Fortis acquired
2.1 million shares of Caribbean Utilities under the Rights Offering for
approximately $25 million (US$24 million), including shares acquired pursuant to
a stand-by purchase commitment in connection with the Rights Offering. In
October 2008, Fortis acquired an additional 267,669 shares of Caribbean
Utilities for approximately $3 million (US$3 million) pursuant to a private
agreement. As a result of this acquisition and the shares acquired under the
Rights Offering, the Corporation's ownership position in Caribbean Utilities
increased from approximately 54 per cent to 57 per cent.
In April 2008, Caribbean Utilities and the Government of the Cayman Islands
entered into a new exclusive 20-year T&D licence and a new non-exclusive
21.5-year generation licence. Under the new T&D licence, customer rates will be
set using an initial targeted ROA of 10 per cent, down from 15 per cent as
allowed under the previous licence, which is reflected through a reduction in
basic electricity rates, effective January 1, 2008.
Following the receipt of the new licences, Standard & Poor's ("S&P") affirmed
its 'A' credit ratings on Caribbean Utilities' long-term corporate credit and
senior unsecured debt and removed the ratings from credit watch.
Caribbean Utilities has changed its fiscal year end from April 30 to December 31
which will result in the Corporation consolidating five months of financial
results of Caribbean Utilities during the fourth quarter of 2008.
For additional information on the impact of the new licences and the nature of
regulation and material regulatory decisions and applications pertaining to
Belize Electricity, Caribbean Utilities and Fortis Turks and Caicos, refer to
"Regulatory Highlights".
NON-REGULATED - FORTIS GENERATION
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Generation (1)
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Energy Sales (GWh) 305 254 51 905 819 86
-------------------------------------------------------------------------
($ millions)
-------------------------------------------------------------------------
Revenue 21 17 4 62 56 6
-------------------------------------------------------------------------
Energy Supply Costs 2 2 - 6 6 -
-------------------------------------------------------------------------
Operating Expenses 3 3 - 11 11 -
-------------------------------------------------------------------------
Amortization 3 3 - 8 8 -
-------------------------------------------------------------------------
Finance Charges 2 2 - 6 7 (1)
-------------------------------------------------------------------------
Corporate Taxes 2 2 - 7 6 1
-------------------------------------------------------------------------
Non-Controlling Interest - - - 2 1 1
-------------------------------------------------------------------------
Earnings 9 5 4 22 17 5
-------------------------------------------------------------------------
(1) Includes the operations of non-regulated generation assets in Belize,
Ontario, central Newfoundland, British Columbia and upper New York
State.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Energy Sales: Energy sales from Non-Regulated - Fortis Generation increased 51
GWh, or 20.1 per cent, quarter over quarter mainly due to higher production in
Belize and upper New York State. Energy sales increased 86 GWh, or 10.5 per
cent, year to date compared to the same period last year driven by higher
production in central Newfoundland, Belize and upper New York State. Higher
production was mainly the result of higher rainfall. At the end of October
2008, the Chalillo reservoir in Belize was at its full supply level.
Revenue: Revenue was $4 million higher quarter over quarter. Factors
contributing to the increase in revenue were: (i) higher production; (ii)
increased average wholesale energy prices per megawatt hour ("MWh") in Ontario,
which were $50.76 during the third quarter of 2008 compared to $47.42 for the
same quarter last year; and (iii) increased average wholesale energy prices per
MWh in upper New York State, which were US$77.79 during the third quarter of
2008 compared to US$57.93 for the same quarter last year.
Revenue was $6 million higher year to date compared to the same period last
year. Factors increasing revenue were: (i) higher production; (ii) increased
average wholesale energy prices per MWh in Ontario, which were $49.19 year to
date compared to $47.63 for the same period last year; and (iii) increased
average wholesale energy prices per MWh in upper New York State, which were
US$77.19 year to date compared to US$56.92 for the same period last year.
Partially offsetting the above factors was the unfavourable impact of foreign
exchange associated with the translation of foreign currency-denominated
revenue, due to the strengthening of the Canadian dollar against the US dollar
compared to the same period last year.
Earnings: Earnings were $4 million higher quarter over quarter and $5 million
higher year to date compared to the same period last year, driven by increased
production and increased average wholesale energy prices. The increase in
year-to-date earnings was partially offset by the unfavourable impact of foreign
exchange associated with the translation of foreign currency-denominated
earnings.
NON-REGULATED - FORTIS PROPERTIES
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-Regulated - Fortis Properties
Financial Highlights (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Hospitality Revenue 40 39 1 108 98 10
-------------------------------------------------------------------------
Real Estate Revenue 16 15 1 47 43 4
-------------------------------------------------------------------------
Total Revenue 56 54 2 155 141 14
-------------------------------------------------------------------------
Operating Expenses 33 32 1 99 89 10
-------------------------------------------------------------------------
Amortization 4 4 - 11 10 1
-------------------------------------------------------------------------
Finance Charges 6 6 - 18 18 -
-------------------------------------------------------------------------
Corporate Taxes 4 4 - 8 8 -
-------------------------------------------------------------------------
Earnings 9 8 1 19 16 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue: Hospitality Revenue was $1 million higher quarter over quarter and $10
million higher year to date compared to the same period last year, reflecting
revenue contribution from the Delta Regina, acquired on August 1, 2007, and
improved performance at Fortis Properties' hospitality operations in Atlantic
Canada.
Revenue per available room ("REVPAR") for the third quarter was $93.64 compared
to $95.11 for the same quarter last year, mainly due to decreased occupancy at
all of the Company's operating regions. REVPAR year to date was $83.04 compared
to $81.27 for the same period last year, mainly due to higher average room rates
at all of the Company's operating regions, partially offset by decreased
occupancy at the Company's operations in western Canada.
Real Estate revenue was $1 million higher quarter over quarter and $4 million
higher year to date compared to the same period last year. The growth in
revenue was attributable to enhanced performance throughout all real estate
operating regions, as well as the contribution from the real estate operations
of the Delta Regina since August 1, 2007. The occupancy rate of the Real Estate
Division was 96.6 per cent as at September 30, 2008, comparable to 96.9 per cent
as at September 30, 2007.
Earnings: Earnings were $1 million higher quarter over quarter and $3 million
higher year to date compared to the same period last year. The increases were
due to improved performance at the Hospitality and Real Estate Divisions,
including contributions from the Delta Regina which was acquired on August 1,
2007.
CORPORATE AND OTHER
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate and Other (1)
Financial Highlights (Unaudited)
Quarter Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Revenue 7 8 (1) 19 16 3
-------------------------------------------------------------------------
Operating Expenses 2 5 (3) 8 8 -
-------------------------------------------------------------------------
Amortization 2 2 - 6 4 2
-------------------------------------------------------------------------
Finance Charges (2) 19 21 (2) 60 47 13
-------------------------------------------------------------------------
Corporate Tax Recovery (6) (6) - (15) (10) (5)
-------------------------------------------------------------------------
Preference Share Dividends 5 2 3 9 5 4
-------------------------------------------------------------------------
Net Corporate and Other
Expenses (15) (16) 1 (49) (38) (11)
-------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses and, from May 17, 2007, the 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 TES
(2) Includes dividends on preference shares classified as long-term
liabilities
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenue: Revenue was $1 million lower quarter over quarter, driven by a
decrease in the number of customer contracts at CWLP, partially offset by higher
interest revenue from increased inter-company lending.
Revenue was $3 million higher year to date compared to the same period last
year. Higher interest revenue from increased inter-company lending was combined
with increased revenue contributions from CWLP. CWLP contributed revenue for a
full year-to-date period in 2008 compared to the partial year-to-date period
last year; however, this increase was partially offset by the impact of a
decrease in the number of customer contracts.
Net Corporate and Other Expenses: Net corporate and other expenses were $1
million lower quarter over quarter, driven by a $2 million tax reduction
associated with the settlement of historical corporate tax matters at Terasen
and lower finance charges, mainly due to lower net credit facility borrowings,
partially offset by increased preference share dividends. The decrease in
operating expenses quarter over quarter was mainly due to decreased activity at
CWLP as a result of a decrease in the number of customer contracts. However, the
decreases in operating expenses and revenue associated with CWLP were
substantially offsetting and did not have a material impact on net corporate and
other expenses quarter over quarter.
Net corporate and other expenses were $11 million higher year to date compared
to the same period last year. The increase reflected Terasen
acquisition-related finance charges, and Terasen corporate and CWLP amortization
costs and operating expenses, less revenue contribution from CWLP, for a full
year-to-date period in 2008 compared to the partial year-to-date period last
year. Net corporate and other expenses also increased due to higher preference
share dividends, partially offset by the $2 million tax reduction associated
with the settlement of historical corporate tax matters at Terasen, and higher
interest revenue from increased inter-company lending.
During the second quarter, Fortis issued 9.2 million 5.25% Five-Year Fixed Rate
Reset First Preference Shares, Series G ("First Preference Shares, Series G")
for gross proceeds of $230 million. The proceeds were used to repay amounts
outstanding under the Corporation's committed credit facility, to fund equity
requirements of FortisAlberta and the Corporation's regulated electric utilities
in the Caribbean, and for general corporate purposes. The increase in
preference share dividends quarter over quarter and year to date compared to the
same period last year reflected dividends on the First Preference Shares, Series
G.
While currently not significant, financial results of TES are also reported in
the Corporate and Other segment. TES expects to increase its activities in the
development, building, owning and operating of innovative geoexchange energy
systems, community piping and energy transfer systems to harness renewable
energy sources. TES is entering into agreements with developers to provide
alternative thermal energy systems for both residential and commercial
development projects in British Columbia. In September 2008, Terasen announced
plans for a new alternative energy program from biogas energy sources from the
conversion of organic waste into a clean renewable energy source. The Company
has issued a preliminary Request for Expressions of Interest for biogas
production. In October 2008, TES signed an agreement to build a centralized
heating and cooling system for a new Okanagan lakefront community project. TES
will own and operate this alternative energy system.
REGULATORY HIGHLIGHTS
A summary of the nature of regulation and material regulatory decisions and
applications for the Corporation's regulated utilities is as follows:
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Nature of Regulation
---------------------------------------------------------------------------
Allowed Allowed Supportive Features
Common Returns Future or
Regulated Regulatory Equity (%) Historical Test Year
Utility Authority (%) 2006 2007 2008 Used to Set Rates
---------------------------------------------------------------------------
ROE Cost of Service
("COS")/ROE
TGI BCUC 35 8.80 8.37 8.62 PBR mechanisms
through 2009:
TGI: 50/50 sharing
of earnings above
or below the
allowed ROE
TGVI BCUC 40 9.50 9.07 9.32 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 9.20 8.77 9.02 COS/ROE
PBR mechanism through
2008, with option to
continue in 2009:
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
---------------------------------------------------------------------------
FortisAlberta Alberta 37 8.93 8.51 8.75 COS/ROE
Utilities
Commission
("AUC")
ROE automatic
adjustment formula
tied to long-term
Canada bond yields
Future Test Year
---------------------------------------------------------------------------
Newfoundland Newfoundland 45 9.24 8.60 8.95 COS/ROE
Power and Labrador +/- +/- +/-
Board of 50 50 50
Commissioners bps bps bps
of Public
Utilities
("PUB")
ROE automatic
adjustment formula
tied to long-term
Canada bond yields
Future Test Year
---------------------------------------------------------------------------
Maritime Island 40 10.25 10.25 10.00 COS/ROE
Electric Regulatory
and Appeals
Commission
("IRAC")
Future Test Year
---------------------------------------------------------------------------
FortisOntario Ontario 46.7 9.00 9.00 9.00 Canadian Niagara
Energy Power - COS/ROE
Board
("OEB")
(Canadian
Niagara
Power)
Franchise Cornwall Electric -
Agreement Price cap with
(Cornwall commodity cost flow
Electric) through
Historical Test Year
---------------------------------------------------------------------------
ROA Four-year COS/ROA
agreements
Belize PUC N/A 10.00 10.00 10.00
Electricity -15.00-15.00 Hurricane Cost
Recovery Rate
Stabilization
Account, the balance
of which is
incorporated into
customer rates on
July 1st of the year
subsequent to the
hurricane
Future Test Year
---------------------------------------------------------------------------
Caribbean Electricity N/A 15.00 15.00 9.00 COS/ROA
Utilities Regulatory -
Authority 11.00
("ERA")
Rate-cap adjustment
mechanism based on
published consumer
price indices
Under the new
Licence, the Company
may apply for a
special additional
rate to customers
in the event of a
disaster, including
a hurricane.
Historical Test Year
---------------------------------------------------------------------------
Fortis Turks Utilities N/A 17.50 17.50 17.50 COS/ROA
and make annual
Caicos filings with
the Energy
Commission
If the actual ROA
is lower than the
allowed ROA, due
to additional costs
resulting from a
hurricane or
other event, the
Company may apply
for an increase
in customer rates
in the following
year.
Future Test Year
---------------------------------------------------------------------------
---------------------------------------------------------------------------
---------------------------------------------------------------------------
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Material Regulatory Decisions and Applications
---------------------------------------------------------------------------
Regulated Utility Summary Description
---------------------------------------------------------------------------
TGI - In December 2007, the BCUC approved various rates at
TGVI TGI and TGVI, including those for mid-stream and
delivery for residential customers in several service
areas, effective January 1, 2008. Increased mid-
stream costs are flowed through to customers without
markup. The approved rates also reflect the impact of
an increase in the allowed ROE for 2008 to 8.62 per
cent and 9.32 per cent for TGI and TGVI, respectively.
- On April 1, 2008, final regulatory approval for the
construction of the 1.5 billion-cubic foot liquefied
natural gas ("LNG") facility on Vancouver Island was
received for a total estimated cost of approximately
$200 million.
- Effective April 1, 2008 and July 1, 2008, the BCUC
approved increases in the commodity rates charged to
TGI customers for natural gas and propane. Effective
October 1, 2008, the BCUC approved decreases in the
commodity rates charged to TGI customers for natural
gas. The commodity cost of natural gas and propane
are flowed through to customers without markup.
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 gas and
propane. Year-to-date 2008, no commodity rate changes
have been made at TGVI.
---------------------------------------------------------------------------
FortisBC - In December 2007, regulatory approval was received of
the NSA associated with 2008 revenue requirements
resulting in a customer rate increase of 2.9 per cent,
effective January 1, 2008. The rate increase is
primarily the result of the Company's capital
expenditure program. Rates for 2008 reflect an
allowed ROE of 9.02 per cent.
- In April 2008, the BCUC approved an interim increase
of 0.8 per cent to FortisBC's customer rates,
effective May 1, 2008, as a result of BC Hydro's
recent interim rate increase, which has increased
FortisBC's cost to purchase power from BC Hydro by
5.06 per cent.
- In June 2008, FortisBC filed its 2009 and 2010 Capital
Plan for gross capital expenditures of approximately
$193 million for 2009 and $196 million for 2010. A
decision on the application is expected in the fourth
quarter of 2008.
- In September 2008, FortisBC filed its Preliminary 2009
Revenue Requirements Application with the BCUC
requesting a 5.6 per cent general rate increase
effective January 1, 2009 and an extension of the PBR
mechanism for the years 2009 through 2011. The
proposed rate increase is the result of the Company's
extensive capital expenditure program and higher power
purchases due to ongoing customer growth and increased
electricity demand. A decision on the application is
expected by the end of 2008.
---------------------------------------------------------------------------
FortisAlberta - Effective January 1, 2008, FortisAlberta became
regulated by the AUC due to the separation of the
Alberta Energy and Utilities Board into two separate
regulatory bodies.
- In February 2008, regulatory approval was received of
the NSA associated with 2008/2009 revenue requirements
resulting in distribution rate increases of 6.8 per
cent, effective January 1, 2008, and 7.3 per cent,
effective January 1, 2009. The approved NSA includes
forecast gross capital expenditures of approximately
$264 million for 2008 and $296 million for 2009,
primarily to meet customer growth and improve system
reliability. The 2008 revenue requirements included
in the 2008/2009 NSA were determined using the 2007
ROE of 8.51 per cent. The impact of the increase in
the ROE to 8.75 per cent for 2008 is subject to
deferral-account treatment and, as such, is being
recognized as earned in 2008 and is expected to be
collected in future customer rates.
- In June 2008, the AUC ruled that a review of the ROE
level, the adjustment mechanism 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. A hearing is scheduled for
the second quarter of 2009.
---------------------------------------------------------------------------
Newfoundland - In December 2007, the PUB approved the Company's NSA
Power associated with the 2008 general rate application,
resulting in an average 2.8 per cent increase in
customer rates, effective January 1, 2008. The rate
increase is largely driven by higher amortization
costs. The rate increase also reflects the impact of
an increase in the allowed ROE to 8.95 per cent for
2008.
- The PUB-approved NSA will also result in, among other
things: (i) the amortization of $7.2 million in 2008
and $4.6 million in each of 2009 and 2010 of the
remaining $16.4 million balance of the original
December 2005 unbilled revenue liability; (ii)
amortization of approximately $3.9 million in each of
2008, 2009 and 2010 of previously deferred
amortization expense; (iii) amortization over a period
of three to five years of certain deferred regulatory
balances; and (iv) for 2008 through 2010, the deferral
of variations in purchase power expense caused by
differences in the actual unit cost of energy and the
unit cost reflected in customer rates to be recovered
from, or refunded to, customers through operation of
the Company's rate stabilization account.
- Effective July 1, 2008, the PUB approved an average
5.9 per cent increase in customer electricity rates,
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 and Labrador Hydro sells to Newfoundland
Power. The increase in customer rates will have no
impact on Newfoundland Power's earnings.
- In July 2008, the Company filed its 2009 Capital
Budget Application with the PUB for approximately $62
million, with more than half of the proposed capital
expenditures relating to replacing aged and
deteriorated components of the electricity system.
The application is currently under review by the PUB.
---------------------------------------------------------------------------
Maritime - In January 2008, IRAC approved, as filed, an increase
Electric in basic electricity rates of 1.8 per cent, effective
April 1, 2008, and approved a maximum allowed ROE of
10.0 per cent for 2008.
- In April 2008, IRAC ordered the energy cost adjustment
mechanism ("ECAM") amortization period of 12 months to
be set at eight months, effective May 1, 2008. The
result is an increase in the flow through in customer
rates of the recovery of ECAM over the shorter
amortization period.
- In July 2008, Maritime Electric filed its 2009 Capital
Budget for approximately $20 million, before customer
contributions. A decision on the Budget is expected by
the end of 2008.
- In September 2008, IRAC approved, as filed, the
Company's amendment of approximately $14 million to
its 2008 Capital Budget to reflect the construction of
a new transmission line to facilitate the expansion of
merchant wind development. The project is being
financed entirely by customer contributions.
- In October 2008, Maritime Electric filed a 2009 basic
rate application. The forecasted combined effect of a
proposed 2009 basic rate increase and a forecasted
increase in energy supply costs, effective April 1,
2009, is 7.46 per cent for residential customers, 7.47
per cent for commercial customers and 8.25 per cent
for large industrial customers. The proposed rate
increases reflect an increase in the amount of energy-
related costs to be collected from customers through
the basic rate component of customer billings. The
proposed increase in the reference cost of energy in
basic rates will result in a decrease in the amount of
energy costs to be collected from customers through
the operation of the ECAM Account. The application
also requests a maximum allowed ROE of 9.75 per cent
for 2009. A decision on the application is expected
by the end of the first quarter of 2009.
---------------------------------------------------------------------------
FortisOntario - In March 2008, the OEB issued its decision relating to
the 2008 Incentive Regulation Mechanism ("IRM")
application filed by Canadian Niagara Power. The
result is an average 1.1 per cent increase in
electricity distribution rates for operations in Fort
Erie, Port Colborne and Gananoque, effective May 1,
2008. The increase is comprised of a 2.1 per cent
increase for inflation, partially offset by a 1 per
cent decrease for a productivity adjustment. Under
the 2008 IRM, Canadian Niagara Power's capital
structure will be deemed at 53.3 per cent debt and
46.7 per cent equity, as part of the OEB's plan to
move to a 60 per cent debt and 40 per cent equity
capital structure over a three-year period.
- Effective July 1, 2008, retail rates at Cornwall
Electric decreased by approximately 6.2 per cent,
attributable to a new 11.5-year wholesale electricity
supply contract negotiated with Hydro-Quebec Energy
Marketing by Cornwall Electric on behalf of its
customers. The new long-term agreement replaces an
existing short-term contract and ensures reliability
of supply and rate stability.
- In August 2008, Canadian Niagara Power filed a 2009
Cost of Service Application requesting the rebasing of
distribution rates using 2009 as a forward test year.
The application assumes a deemed capital structure of
56.7 per cent debt and 43.3 per cent equity and
reflects a preliminary ROE of 8.39 per cent. The
application proposes 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 are
primarily driven by the impact of distribution system
upgrades. Canadian Niagara Power expects a hearing
process associated with the application to begin in
the fourth quarter of 2008 with a decision to be
received in April 2009.
---------------------------------------------------------------------------
Belize - In March 2008, the newly elected Government of Belize
Electricity repealed December 2007 amendments to the Electricity
(Tariffs, Charges and Quality of Services Standards)
Bylaws. The amendments had simplified Belize
Electricity's rate-setting methodology, allowed for
improved rate stabilization and settled outstanding
matters related to the PUC's Final Decision on
electricity rates for the period July 1, 2007 through
June 30, 2008.
- In March 2008, Belize Electricity filed an application
requesting an increase in the cost of power component
of the average electricity rate by 15 per cent, or
BZ6.5 cents per kWh, as a result of the rapid increase
in the cost of power due to increasing world oil
prices. The application was disallowed by the PUC who
cited that, in the interim, a decrease in the
Company's operating expenses and capital expenditures
levels would help offset the impact on cash flow of
the increasing cost of power. Additionally, the PUC
indicated it would defer its detailed analysis of the
high deferrals of cost of power into Belize
Electricity's cost of power rate stabilization account
("CPRSA") until the Annual Tariff Review Proceeding for
the annual tariff period for July 1, 2008 to June 30,
2009.
- In April 2008, Belize Electricity filed its Annual
Tariff Review Application for the annual tariff period
from July 1, 2008 to June 30, 2009 ("2008/2009 Rate
Application") requesting a 13.4 per cent increase in
the average electricity rate, as a result of an
increase in the cost of power component of the rate
and an increase in the recovery of the CPRSA.
- In May 2008, the PUC issued its Initial Decision on
Belize Electricity's 2008/2009 Rate Application. The
Initial Decision denied any average rate increase and
approved, among other things, a retroactive adjustment
to Belize Electricity's CPRSA. Belize Electricity
objected to the Initial Decision, which resulted in a
review of the Initial Decision by a PUC-appointed
Independent Expert. The report of the Independent
Expert reiterated many of Belize Electricity's
concerns pertaining to the Initial Decision.
- In June 2008, the PUC issued its Final Decision on
Belize Electricity's 2008/2009 Rate Application which
rejected most of the recommendations of the
Independent Expert and failed to increase the overall
average electricity rate. 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 target allowed ROA to 10 per cent from
12 per cent through a reduction in the VAD component
of the average electricity rate. The Final Decision
would have the impact of reducing the Corporation's
share of Belize Electricity's earnings by
approximately $5 million over the next 12 months. The
Final Decision does not impact the Corporation's non-
regulated generation operations in Belize.
- As a direct result of the Final Decision, Belize
Electricity has recorded an $18 million (BZ$36
million) charge ($13 million of which is the
Corporation's share) to energy supply costs during the
second quarter of 2008.
- On July 25, 2008, Belize Electricity filed
applications with the Supreme Court of Belize for
leave to apply for judicial review of 2008 amended
bylaws, upon which the Final Decision was premised,
and appeal of the Final Decision. Leave was granted
on October 3, 2008. It is expected that the judicial
review will be heard in late 2008. The findings of
the Supreme Court of Belize on the validity of the
2008 amended bylaws will determine the necessity of
further action by Belize Electricity with respect to
the appeal of the Final Decision.
- 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 rates to reflect actual costs of
power. The automatic adjustment mechanism, which is
retroactive effective September 1, 2008, will allow
for the collection from, or rebate to, customers of
actual costs of power which vary from a reference cost
of power, set at BZ31.2 cents per kWh for the period
from July 1, 2008 to December 31, 2008, by more than a
threshold of 10 per cent. Actual costs of power for
July 2008 and August 2008 were not outside the 10 per
cent threshold.
---------------------------------------------------------------------------
Caribbean - In December 2007, an Agreement in Principle ("AIP")
Utilities was reached with the Government of the Cayman Islands
on the terms of a new exclusive T&D licence and a new
non-exclusive generation licence.
- In April 2008, the new licences were granted. The
terms of the new licences include competition for
future generation capacity and general promotion of
renewable resources of energy. The T&D licence is for
an initial period of 20 years, expiring April 2028,
with a provision for automatic renewal. The generation
licence is for a period of 21.5 years, expiring
September 2029. The terms of the new licences remained
substantially the same as the terms outlined in the
AIP.
- Effective January 1, 2008, as a result of the AIP and
subsequent granting of the new licences, basic
customer rates were reduced by 3.25 per cent, the CRS
was removed, a fuel-duty rebate funded by the
Government of the Cayman Islands was implemented for
residential customers consuming less than 1,500 kWh
monthly, and basic rates were restructured to extract
all fuel costs and licence fee amounts which are now
to be fully flowed through to customers. The 3.25 per
cent reduction in basic rates will reduce annual
revenue by approximately US$2.1 million.
Additionally, Caribbean Utilities has forgone
US$2.6 million of revenue in 2008 as a result of the
early elimination of the CRS. A new fuel and oil rate
factor was also established to provide for full flow
through of fuel and oil costs to customers.
- Following the initial basic rate reduction, customer
rates will be frozen until May 31, 2009 and will be
subject to annual review and adjustment each June
thereafter. Under the new T&D licence, a mechanism
will be used to adjust basic rates in accordance with
a formula that is based on published consumer price
indices, thereby taking inflation into account. The
rate-adjustment mechanism is designed to maintain
Caribbean Utilities' ROA in a targeted range of 9 per
cent to 11 per cent, down from an allowed ROA of 15
per cent that was permitted under the previous
licence. The recently amended Electricity Regularity
Authority Law (2005 Revision) provides for the conduct
of a competitive bid process to be managed by the ERA
for new generating capacity and the replacement of
retired generating capacity. The first competitive
process under the new generation licence began in May
2008 with a filing of a Certificate of Need by
Caribbean Utilities for the installation of 16 MW
of additional generating capacity in each of 2011 and
2012.
- In July 2008, Caribbean Utilities filed with the
regulator a Five-Year Capital Investment Plan
totalling US$255 million, including US$80 million
related to new generation that is expected to be
solicited. A decision on the Plan is expected by the
end of 2008.
- In July 2008, Caribbean Utilities began a formal
request for expressions of interest from qualified
wind-generation developers for a wind-generation
project for up to 10 MW. The ERA has endorsed this
initiative and any power purchase agreements or
generating licence arising from this initiative will
be subject to ERA approval.
---------------------------------------------------------------------------
Fortis Turks - In March 2008, Fortis Turks and Caicos submitted
and Caicos its 2007 annual regulatory filing outlining the
Company's performance in 2007 and its capital
expansion plans for 2008. Fortis Turks and Caicos'
achieved ROA in 2007 was less than that permitted
under its licences; however, the Company did not seek
any basic rate increases in 2008.
- In May 2008, Fortis Turks and Caicos received approval
from the Government of Turks and Caicos Islands to
supply wholesale electricity under an exclusive
licence to Dellis Cay on the Turks and Caicos Islands.
---------------------------------------------------------------------------
---------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between September 30, 2008 and December 31, 2007.
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Fortis Inc.
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between September 30, 2008 and December 31, 2007
---------------------------------------------------------------------------
Increase/
Balance Sheet (Decrease)
Account ($ millions) Explanation
---------------------------------------------------------------------------
Accounts receivable (177) The decrease was primarily due to the
impact of a seasonal reduction in sales
driven by the Terasen Gas companies,
FortisBC and Newfoundland Power.
---------------------------------------------------------------------------
Inventories of gas, 101 The increase was driven by a normal
materials and seasonal injection of gas in storage for
supplies consumption in the upcoming winter months.
---------------------------------------------------------------------------
Deferred charges 36 The increase was mainly due to and other
assets contributions made by FortisAlberta to
the AESO for transmission capital
projects during the nine months ended
September 30, 2008.
---------------------------------------------------------------------------
Utility capital assets 376 The increase primarily related to $612
million invested in electricity and
gas systems, partially offset by
customer contributions, amortization for
the nine months ended September 30, 2008,
and the impact of foreign exchange on
the translation of US dollar-denominated
utility capital assets.
---------------------------------------------------------------------------
Goodwill 15 The increase primarily related to the
impact of foreign exchange on the
translation of US dollar-denominated
goodwill and goodwill associated with
the Corporation's additional investment
in Caribbean Utilities as a result of
the Corporation's participation in
Caribbean Utilities' Rights Offering
in August 2008.
---------------------------------------------------------------------------
Short-term borrowings (35) The decrease was primarily due to the
repayment of short-term borrowings by TGI
and Maritime Electric with proceeds
from the issuance of long-term debt,
partially offset by additional borrowings
by the Terasen Gas companies due to
seasonality of its operations.
---------------------------------------------------------------------------
Accounts payable and (88) The decrease was due to the
accrued charges recording of the change in the
fair market value of the natural gas
derivative contracts, the timing of
FortisAlberta's payments to the AESO for
transmission costs, decreased amounts
owing for purchased power at
Newfoundland Power due to seasonality
of operations and the timing of property
tax payments at the Terasen Gas
companies. The decrease was partially
offset by higher amounts at Caribbean
Utilities due to increased fuel costs.
---------------------------------------------------------------------------
Income taxes payable 19 The increase was mainly due to tax
associated with regulatory-deferral
accounts at the Terasen Gas companies,
combined with the timing of income tax
payments and the accrual of current
income taxes at the Terasen Gas
companies and Newfoundland Power.
The increase was partially offset by an
approximate $17 million payment associated
with the settlement of historical
tax matters at Terasen.
---------------------------------------------------------------------------
Regulatory liabilities 15 The increase was driven by an increase
- current and long-term in the regulatory provision for future
asset removal and site restoration
costs.
---------------------------------------------------------------------------
Deferred credits 14 The increase was primarily due to an
increase in supplementary defined
benefit pension and other post-employment
benefit obligations.
---------------------------------------------------------------------------
Long-term debt and capital 98 The increase was primarily due to
lease obligations the issuance of long-term debt
(including current and the impact of foreign exchange on
portion) the translation of US dollar-
denominated debt, partially offset
by a net $374 million decrease in
committed credit-facility
borrowings, driven by net
repayments by the Terasen Gas companies
and the Corporation, as well as regularly
scheduled debt repayments.
The issuance of long-term debt, primarily
to repay committed credit-facility
borrowings, short-term borrowings and
$188 million of maturing long-term debt,
was comprised of a $250 million unsecured
debenture offering by TGI, a $250 million
unsecured debenture offering by TGVI, a
$100 million senior unsecured debenture
offering by FortisAlberta and a $60 million
secured first mortgage bond issue by
Maritime Electric.
---------------------------------------------------------------------------
Non-controlling interest 15 The increase primarily related to the
impact of foreign exchange on the
translation of US dollar-denominated
non-controlling interest amounts,
combined with the Corporation's
non-controlling interest in Caribbean
Utilities' US$28 million Rights Offering.
The increase was partially offset by
the Corporation's non-controlling
interest in the year-to-date net
loss incurred at Belize Electricity
as a result of the PUC's decision on
the Company's 2008/2009 rate application.
---------------------------------------------------------------------------
Shareholders' equity 315 The increase was driven by a $230 million
preference share issue ($225 million net
of after-tax expenses) combined with
net earnings reported for the nine months
ended September 30, 2008, less common
share dividends. The remainder of the
increase related to the issuance of
Common Shares under the Corporation's
share purchase, dividend reinvestment
and stock option plans and a decrease
in accumulated other comprehensive loss.
---------------------------------------------------------------------------
---------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The following table outlines the summary of cash flows.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Summary of Cash Flows (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Cash, beginning
of period 59 63 (4) 58 41 17
-------------------------------------------------------------------------
Cash provided by
(used in)
-------------------------------------------------------------------------
Operating activities 17 59 (42) 449 221 228
-------------------------------------------------------------------------
Investing activities (219) (252) 33 (577) (1,799) 1,222
-------------------------------------------------------------------------
Financing activities 211 182 29 138 1,591 (1,453)
-------------------------------------------------------------------------
Foreign currency
impact on cash
balances - (1) 1 - (3) 3
-------------------------------------------------------------------------
Cash, end of period 68 51 17 68 51 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $17 million compared to $59 million for the same
quarter last year. The decrease was driven by FortisAlberta; however, cash flow
from operating activities, after working capital adjustments, for the third
quarter of 2007 included approximately $28 million in proceeds from the sale of
FortisAlberta's 2006 AESO charges deferral account and a $12 million cash tax
refund.
Cash flow from operating activities, after working capital adjustments, was $228
million higher year to date compared to the same period last year. An increase
in cash flow from operating activities, after working capital adjustments, of
$304 million at the Terasen Gas companies, combined with the impact of
favourable working capital changes at Newfoundland Power, was partially offset
by lower cash flow from operating activities, after working capital adjustments,
at FortisAlberta, for the reasons as described above for the quarter, as well as
the impact of the timing of the payment of AESO transmission cost accruals at
FortisAlberta. The Terasen Gas companies contributed to the financial results
of the Corporation for a full year-to-date period in 2008 compared to the
partial year-to-date period last year.
Investing Activities: Cash used in investing activities was $33 million lower
quarter over quarter. During the third quarter of 2007, Fortis Properties
completed the acquisition of the Delta Regina for a purchase price of
approximately $50 million. Excluding the impact of the above acquisition last
year, cash used in investing activities was $17 million higher quarter over
quarter, driven by higher utility capital expenditures and changes in deferred
charges, other assets and deferred credits, partially offset by higher
contributions received in aid of construction.
Cash used in investing activities was $1.2 billion lower year to date compared
to the same period last year. Investing activities last year, however, included
the impact of the approximate $1.3 billion cash payment for the acquisition of
Terasen in May 2007. Excluding the impact of the acquisitions of Terasen and
the Delta Regina last year, cash used in investing activities was $81 million
higher year to date compared to the same period last year. The increase was
driven by higher utility capital expenditures and changes in deferred charges,
other assets and deferred credits, partially offset by an increase in proceeds
from the sale of capital assets, driven by $14 million of proceeds received in
January 2008 associated with the December 2007 sale of surplus land by TGI.
Gross utility capital expenditures were $231 million for the third quarter of
2008, $19 million higher than for the same quarter last year. The increase was
driven by the Terasen Gas companies, FortisAlberta and Fortis Turks and Caicos.
Gross utility capital expenditures were $612 million year to date, $73 million
higher than for the same period last year. The increase was driven by the
Terasen Gas companies and FortisAlberta, partially offset by lower capital
spending at FortisBC.
The net increase in the use of cash associated with changes in deferred charges,
other assets and deferred credits of $13 million quarter over quarter and $27
million year to date compared to the same period last year was driven by higher
contributions by FortisAlberta to AESO transmission capital projects.
Financing Activities: Cash provided by financing activities was $29 million
higher quarter over quarter, primarily due to higher net borrowings under
committed credit facilities and higher proceeds from net short-term borrowings,
partially offset by lower proceeds from long-term debt.
Cash provided by financing activities was approximately $1.5 billion lower year
to date compared to the same period last year. Financing activities last year
included the impact of the issuance of Common Shares for gross proceeds of $1.15
billion, upon conversion of Subscription Receipts that were initially issued in
March 2007, to finance a significant portion of the cash purchase price of
Terasen. Excluding the impact of financing the acquisition of Terasen last
year, cash provided by financing activities was $351 million lower year to date
compared to the same period last year. The decrease was mainly due to higher
net repayments of committed credit facility borrowings and higher repayments of
long-term debt, partially offset by proceeds from the issuance of preference
shares during the second quarter of 2008 and higher proceeds from long-term
debt. Additionally, during the first quarter of 2007, the Corporation publicly
issued 5.17 million Common Shares for gross proceeds of approximately $150
million ($143 million net of costs).
Proceeds from net short-term borrowings were $160 million for the third quarter
of 2008, or $61 million higher than for the same quarter last year. The
increase was driven by the Terasen Gas companies and FortisBC, partially offset
by net repayments of short-term borrowings by Caribbean Utilities. Net
repayments of short-term borrowings were $36 million year to date compared to
proceeds from net short-term borrowings of $29 million for the same period last
year. The net repayments year-to-date 2008 were driven by Maritime Electric.
Proceeds from long-term debt, net of issue costs, net borrowings (repayments)
under committed credit facilities, and repayments of long-term debt and capital
lease obligations for the quarter and year to date compared to the same periods
last year are summarized in the following tables.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Terasen Gas
companies - - - 496(1) - 496
(2)
-------------------------------------------------------------------------
FortisAlberta - - - 99(3) 110(4) (11)
-------------------------------------------------------------------------
FortisBC - 104(5) (104) - 104(5) (104)
-------------------------------------------------------------------------
Newfoundland Power - 70(6) (70) - 70(6) (70)
-------------------------------------------------------------------------
Maritime Electric - - - 60(7) - 60
-------------------------------------------------------------------------
Caribbean Utilities - - - - 32(8) (32)
-------------------------------------------------------------------------
Corporate - 209(9) (209) - 209(9) (209)
-------------------------------------------------------------------------
Other - 7 (7) 4 8 (4)
-------------------------------------------------------------------------
Total - 390 (390) 659 533 126
-------------------------------------------------------------------------
(1) Issued February 2008, $250 million 6.05% Medium-Term Note Debentures by
TGVI, due February 2038. The net proceeds were used to repay committed
credit-facility borrowings.
(2) Issued May 2008, $250 million 5.80% Medium-Term Note Debentures by TGI,
due May 2038. The net proceeds were primarily used to repay maturing
$188 million 6.20% debentures and short-term borrowings.
(3) Issued April 2008, $100 million 5.85% Senior Unsecured Debentures, due
April 2038. The net proceeds were used to repay committed credit-
facility borrowings.
(4) Issued January 2007, $110 million 4.99% Senior Unsecured Debentures,
due January 2047. The net proceeds were used to repay committed
credit-facility borrowings.
(5) Issued July 2007, $105 million 5.90% Unsecured Debentures, due July
2047. The net proceeds were used to repay committed credit-facility
borrowings and for general corporate purposes, including capital
expenditures.
(6) Issued August 2007, $70 million 5.90% Secured First Mortgage Sinking
Fund Bonds, due August 2037. The net proceeds were used to repay
committed credit-facility borrowings.
(7) Issued April 2008, $60 million 6.05% Secured First Mortgage Bonds, due
April 2038. The proceeds were used to repay short-term borrowings.
(8) Issued June 2007, US$30 million 5.65% Senior Unsecured Notes, due June
2022. The proceeds were used to repay debt and to finance capital
expenditures.
(9) Issued September 2007, US$200 million 6.60% Secured Unsecured Notes,
due September 2037. The net proceeds were used to repay committed
credit-facility borrowings associated with the Terasen acquisition and
for general corporate purposes.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Terasen Gas
companies - - - (261) - (261)
-------------------------------------------------------------------------
FortisAlberta 47 (16) 63 45 (88) 133
-------------------------------------------------------------------------
FortisBC 2 (31) 33 10 (21) 31
-------------------------------------------------------------------------
Newfoundland Power 8 (64) 72 (6) (33) 27
-------------------------------------------------------------------------
Corporate 46 (150) 196 (162)(1) 63(2) (225)
-------------------------------------------------------------------------
Total 103 (261) 364 (374) (79) (295)
-------------------------------------------------------------------------
(1) During the second quarter of 2008, 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). The remaining net proceeds from the
issuance of preference shares were used to fund equity requirements of
FortisAlberta and the Corporation's regulated electric utilities in the
Caribbean, and for general corporate purposes.
(2) During the second quarter of 2007, borrowings under the Corporation's
committed credit facility primarily related to financing, on an interim
basis, the remaining $125 million net cash purchase price of Terasen on
May 17, 2007, in addition to certain acquisition costs and Common Share
issue costs; to repay certain short-term indebtedness assumed upon the
acquisition of Terasen; and for general corporate purposes. During the
first quarter of 2007, the Corporation repaid approximately $84 million
of committed credit-facility borrowings financed with partial proceeds
from a 5.17 million Common Share issue in January 2007.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Borrowings by the utilities under committed credit facilities are primarily in
support of their respective capital expenditure programs and/or for working
capital requirements. Repayments are primarily financed through the issuance of
long-term debt and/or cash from operations. From time to time, proceeds from
preference share, common share and long-term debt issues are used to repay
borrowings under the Corporation's committed credit facility.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease Obligations (Unaudited)
Periods Ended September 30
-------------------------------------------------------------------------
Quarter Year-to-date
-------------------------------------------------------------------------
($ millions) 2008 2007 Variance 2008 2007 Variance
-------------------------------------------------------------------------
Terasen Gas companies - - - (194)(1) - (194)
-------------------------------------------------------------------------
Caribbean Utilities (11) (8) (3) (11) (19) 8
-------------------------------------------------------------------------
Fortis Properties (3) (3) - (9) (17) 8
-------------------------------------------------------------------------
Other (1) (4) 3 (6) (12) 6
-------------------------------------------------------------------------
Total (15) (15) - (220) (48) (172)
-------------------------------------------------------------------------
(1) In May 2008, partial proceeds from TGI's $250 million debenture
offering were used to repay maturing $188 million 6.20% debentures.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net proceeds associated with the issuance of Common Shares under the
Corporation's share purchase and stock options plans during the third quarter
were $5 million compared to $8 million for the same quarter last year and were
$16 million year to date compared to $17 million for the same period last year.
On May 17, 2007, the Corporation publicly issued 44.3 million Common Shares for
gross proceeds of approximately $1.15 billion ($1.1 billion net of costs) upon
conversion of Subscription Receipts that were initially issued in March 2007 to
finance a significant portion of the net cash purchase price of Terasen. In
January 2007, 5.17 million Common Shares were publicly issued for gross proceeds
of approximately $150 million ($143 million net of costs). Partial net proceeds
from the Common Share issue in January 2007 were used to repay indebtedness
incurred under the Corporation's committed credit facility. The remainder of
the net proceeds was used to fund equity requirements of the Corporation's
regulated electric utilities in western Canada, in support of their respective
capital expenditure programs, and for general corporate purposes.
Common Share dividends were $39 million during the third quarter of 2008, up $6
million from the same quarter last year. The increase was primarily due to a
higher dividend per Common Share compared to the same quarter last year. Common
share dividends were $118 million year to date, up $29 million from the same
period last year. The increase was due to an increase in the number of Common
Shares outstanding, primarily as a result of the issuance of Common Shares
pursuant to the Terasen acquisition in May 2007, and a higher dividend per
Common Share compared to the same period last year. The dividend per Common
Share for each of the first three quarters of 2008 was $0.25, while the dividend
per Common Share for each of the first three quarters of last year was $0.21.
Preference share dividends increased $3 million quarter over quarter and
increased $4 million year to date compared to the same period last year related
to the 9.2 million First Preference shares, Series G issued during the second
quarter of 2008.
Contractual obligations: As at September 30, 2008, consolidated contractual
obligations over the next five 12-month periods and for periods thereafter are
outlined in the following table. The nature and amount of the contractual
obligations are consistent with those disclosed in the MD&A for the year ended
December 31, 2007, except for those described below for FortisOntario, Maritime
Electric, Caribbean Utilities and Fortis Turks and Caicos.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Fortis Inc.
Contractual Obligations (Unaudited)
as at September 30, 2008
--------------------------------------------------------------------------
lesser
or
egual greater greater
than than 1- 4-5 than
($ millions) Total 1 year 3 years years 5 years
--------------------------------------------------------------------------
Long-term debt 5,158 374 299 217 4,268
--------------------------------------------------------------------------
Brilliant Terminal Station 64 3 5 5 51
--------------------------------------------------------------------------
Gas purchase contract
obligations (based on index
prices as at September
30, 2008) 770 747 23 - -
--------------------------------------------------------------------------
Power purchase obligations
FortisBC 2,825 37 75 73 2,640
FortisOntario (1) 567 40 94 98 335
Maritime Electric (2) 90 70 2 2 16
Belize Electricity 15 4 3 2 6
--------------------------------------------------------------------------
Capital cost 391 14 38 36 303
--------------------------------------------------------------------------
Joint-use asset and shared
service agreements 63 1 7 6 49
--------------------------------------------------------------------------
Office lease - FortisBC 20 - 4 2 14
--------------------------------------------------------------------------
Operating lease obligations 163 18 33 28 84
--------------------------------------------------------------------------
Equipment purchase commitment
- Caribbean Utilities (3) 20 10 10 - -
--------------------------------------------------------------------------
Other 25 5 9 6 5
--------------------------------------------------------------------------
Total 10,171 1,323 602 475 7,771
--------------------------------------------------------------------------
(1) Included in FortisOntario's power purchase obligations is a new 11.5-
year take-or-pay contract between Cornwall Electric and Hydro-Quebec
Energy Marketing for the supply of electricity and capacity. The
contract, which expires on December 31, 2019, replaces the previous
two-year contract that expired on June 30, 2008. This take-or-pay
contract provides energy up to 100 MW on an as-needed basis and
provides a minimum 300,000 MWh of energy per contract year beginning
July 1, 2008.
(2) Maritime Electric has two new take-or-pay contracts for the purchase of
either energy or capacity. The contracts total approximately $90
million through November 30, 2032. The take-or-pay contract with New
Brunswick Power includes, among other things, replacement energy and
capacity for the Point Lepreau Nuclear Generating Station during its
18-month refurbishment outage. The other take-or-pay contract is for
transmission capacity allowing Maritime Electric to reserve 30 MW of
capacity on the new International Power Line into the United States.
(3) Caribbean Utilities has entered into an agreement to purchase a 16-MW
diesel generating unit and related equipment from a supplier in Germany
for approximately US$24 million. The unit is expected to be
commissioned in summer 2009. Approximately US$5 million has been
incurred under the project as at September 30, 2008.
Other Contractual Obligations:
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, required to be purchased annually for each of the 12-
month periods ended April 30 are: 2009 - 26 and 2010 - 28.
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.
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Capital Structure: The Corporation's principal businesses of regulated gas and
electricity distribution require ongoing access to capital to allow them to fund
maintenance and expansion of infrastructure. Wherever possible, Fortis raises
debt at the subsidiary level to ensure regulatory transparency, tax efficiency
and financing flexibility. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40
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 utility's
customer rates. As well, the Corporation and its larger regulated utilities
have secured multi-year 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. Fortis generally finances a
significant portion of acquisitions with proceeds from common and preference
share issues.
The consolidated capital structure of Fortis is presented in the following table.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Capital Structure (Unaudited)
As at
-------------------------------------------------------------------------
September 30, 2008 December 31, 2007
-------------------------------------------------------------------------
($ millions) (%) ($ millions) (%)
-------------------------------------------------------------------------
Total debt and
capital lease
obligations
(net of cash) (1) 5,529 62.2 5,476 64.3
-------------------------------------------------------------------------
Preference shares (2) 667 7.5 442 5.2
-------------------------------------------------------------------------
Common shareholders'
equity 2,691 30.3 2,601 30.5
-------------------------------------------------------------------------
Total 8,887 100.0 8,519 100.0
-------------------------------------------------------------------------
(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 improvement in the capital structure from December 2007 was primarily due to
a $230 million ($225 million net of after-tax expenses) preference share issue,
partially offset by an increase in consolidated debt. The increase in
consolidated debt was driven by increased debt levels at FortisAlberta in
support of its significant capital expenditure program and a primarily seasonal
increase in credit facility borrowings at the Terasen Gas companies, partially
offset by the repayment of credit facility borrowings by the Corporation with
partial proceeds from the preference share issue. The capital structure was
also favourably impacted by net earnings applicable to common shares, less
common share dividends, of $51 million during the first nine months of 2008.
The Corporation's credit ratings are as follows:
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
acquisitions in 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.
Year to date, gross consolidated capital expenditures were $623 million. A
breakdown of gross capital expenditures year to date by segment is provided in
the following table.
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Gross Capital Expenditures (Unaudited)
Year-to-date September 30, 2008
($ millions)
-----------------------------------------------------------------------
Other
Regu- Total
Tera- lated Regu- Regu- Non-
sen - Uti- lated lated Regu
Gas Fortis lities Uti- Uti- lated
Compa- Alber- NF Cana- lities lities Uti- Fortis
nies ta FortisBC Power dian - Cana- Carib- lity Proper- Total
(1) (1)(2) (1) (1) (1) dian bean (3) ties (4)
-----------------------------------------------------------------------
152 222 81 47 28 530 65 17 11 623
-----------------------------------------------------------------------
(1) Includes asset removal and site restoration expenditures which are
permissible in rate base
(2) Excludes payments of $23 million made to the AESO for investment in
transmission capital projects
(3) Includes non-regulated generation, non-regulated gas utility and
Corporate capital expenditures
(4) Includes expenditures associated with assets under construction
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Gross consolidated capital expenditures for 2008 are expected to exceed $900
million. Planned capital expenditures are based on detailed forecasts of energy
demand, weather, cost of labour and materials, as well as other factors which
could change and cause actual expenditures to differ from forecasts. The
significant changes in the expected level, nature and timing of certain capital
projects for 2008 from those disclosed in the MD&A for the year ended December
31, 2007 are described below.
In April 2008, TGVI received approval from the BCUC to proceed with the
engineering, procurement and construction ("EPC") of the LNG storage facility on
Vancouver Island for a total cost of approximately $200 million. As a result,
the Company entered into an EPC contract with a third party for the construction
of the facility. The contract includes approximately $55 million to be paid in
US dollars. As a result, TGVI has entered into a three-year US dollar
forward-purchase contract which will mitigate currency fluctuations on the US
dollar portion of the EPC contract. Construction commenced on the LNG storage
facility during the second quarter of 2008.
TGVI's construction of an approximate $40 million 50-kilometre pipeline lateral
from Squamish to Whistler continues and, as at September 30, 2008, approximately
47 kilometres of the pipeline had been constructed. Originally scheduled to be
completed by summer 2008, the pipeline lateral is now expected to be completed
in early 2009, slightly later than originally planned, due to changes in the way
the Company can sequence the pipeline construction as a result of the Province's
Sea-to-Sky Highway Improvement Project Plan ("Highway Project"). The pipeline
is being built in conjunction with the Highway Project and the pipeline route
mainly falls within the highway right of way. Conversion of the Resort
Municipality of Whistler from propane to natural gas will occur in spring 2009
and take approximately three months to complete. TGVI does not expect any
significant change in the cost to complete this capital project as a result of
this delay.
During the third quarter of 2008, FortisAlberta began the second phase of
deployment of the replacement of conventional meters with new Automated Meter
Infrastructure ("AMI") technology. This phase is part of an overall $124
million project to convert approximately 435,000 customers to AMI technology
over a four-year period that began in 2007. FortisAlberta expects to invest
between $293 million and $303 million in gross capital projects in 2008,
including asset removal and site restoration costs, up from $264 million as
disclosed at December 31, 2007, mainly due to customer growth.
In October 2008, the BCUC approved FortisBC's proposed $141 million Okanagan
Transmission Reinforcement project, which was included in FortisBC's 2009 and
2010 Capital Plan. The project relates to upgrading the existing overhead
transmission line from 161 kilovolts ("kV") to 230 kV from Vaseux Lake to Oliver
and Penticton, and building a new 230-kV transmission line from Vaseux Lake to
Penticton. FortisBC anticipates that construction of the project will begin in
the spring of 2009 for expected completion in 2011.
Fortis Properties will be expanding its Holiday Inn Kelowna hotel including
adding 70 rooms and 4,000 square feet of meeting room space with construction to
begin late in 2008. Completion of the expansion is expected by January 2010 at
a total capital cost of approximately $13 million.
In April 2008, Caribbean Utilities entered into an agreement to purchase a 16-MW
diesel generating unit and related equipment from a supplier in Germany for
approximately US$24 million over the period 2008 and 2009 with the unit expected
to be commissioned in summer 2009.
Fortis expects gross consolidated capital expenditures to exceed $4.5 billion
over the next five years and to be driven by the Terasen Gas companies,
FortisAlberta, FortisBC and the Corporation's regulated utility operations in
the Caribbean. The increase in the expected capital expenditures over the next
five years from the original estimate of $4 billion arises from additional
capital projects forecasted by the Terasen Gas companies, FortisBC and Caribbean
Utilities.
Cash Flows: 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 for 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 shares and preference shares is dependent on the financial results of
the operating subsidiaries and the related cash payments from these
subsidiaries. Certain regulated subsidiaries may be subject to restrictions
which may limit their ability to distribute cash to Fortis. Cash required of
Fortis to support subsidiary capital expenditure programs and to finance
acquisitions is expected to be derived from a combination of borrowings under
credit facilities and 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 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 annual long-term debt maturities are expected to be
approximately $180 million. The combination of available credit facilities and
low annual debt maturities provides the Corporation and its subsidiaries with
flexibility in the timing of access to the debt and equity capital markets.
As a result of the PUC's Final Decision on Belize Electricity's 2008/2009 rate
application, Belize Electricity does not meet certain debt covenant financial
ratios resulting in approximately $16 million (BZ$30 million) of indebtedness
being in default as at September 30, 2008 and Belize Electricity being
prohibited from incurring new indebtedness or declaring dividends under certain
of these debt covenants. The Company has informed the lenders of the situation
and has requested appropriate waivers. As at September 30, 2008, the above debt
was classified as current in the consolidated balance sheet.
As at September 30, 2008, the Corporation and its subsidiaries had consolidated
authorized lines of credit of $2.2 billion, of which $1.5 billion was unused.
The credit facilities are syndicated almost entirely with the seven largest
Canadian banks with no one bank holding more than 25 per cent of these
facilities. The following summary outlines the credit facilities of the
Corporation and its subsidiaries.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Fortis Inc.
Credit Facilities (Unaudited)
-------------------------------------------------------------------------
Total Total
as at as at
Corporate Regulated Fortis September December
($ millions) and Other Utilities Properties 30, 2008 31, 2007
-------------------------------------------------------------------------
Total credit facilities 715 1,491 13 2,219 2,234
-------------------------------------------------------------------------
Credit facilities
utilized:
-------------------------------------------------------------------------
Short-term borrowings - (440) - (440) (475)
-------------------------------------------------------------------------
Long-term debt
(including current
portion) (46) (110) - (156) (530)
-------------------------------------------------------------------------
Letters of credit outstanding (1) (89) (1) (91) (159)
-------------------------------------------------------------------------
Credit facilities available 668 852 12 1,532 1,070
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At September 30, 2008 and December 31, 2007, 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
Letters of credit of $50 million previously outstanding at Terasen Inc., related
to its previously owned petroleum transportation business and secured by a
letter of credit from the former parent company, were cancelled during the
second quarter of 2008.
Regulated Utilities
In April 2008, FortisBC renegotiated and amended its $150 million unsecured
committed revolving credit facility, extending the maturity date of the $50
million portion of the facility to May 2011 from May 2010 and extending the $100
million portion to May 2009 from May 2008. The Company has the option to
increase the credit facility to an aggregate of $200 million, subject to bank
approval.
In April 2008, Maritime Electric repaid all outstanding borrowings under its $25
million unsecured credit facility with partial proceeds from a $60 million bond
issue. The credit facility matured in May 2008 and was not renewed. As at
September 30, 3008, Maritime Electric had a $50 million unsecured revolving
credit facility.
In July 2008, TGI renegotiated, on substantially similar terms, its $500 million
unsecured committed revolving credit facility extending the maturity date of the
facility to August 2013 from August 2012.
In August 2008, Newfoundland Power renegotiated, on substantially similar terms,
its $100 million committed revolving credit facility extending the maturity date
to August 2011 from January 2009.
FINANCIAL INSTRUMENTS
The carrying values of financial instruments included in current assets, current
liabilities, deferred charges and other assets, and deferred credits in the
consolidated balance sheets of Fortis approximate their fair value, reflecting
the short-term maturity, normal trade credit terms and/or nature of these
instruments. The fair value of long-term debt is calculated by using quoted
market prices, when available, or by discounting the future cash flow of each
debt instrument at the estimated yield to maturity for the same or similar debt
issues at the balance sheet date. Since the Corporation does not intend to
settle the long-term debt prior to maturity, the fair value estimate does not
represent an actual liability and, therefore, does not include exchange or
settlement costs. The fair value of the Corporation's preference shares is
determined using quoted market prices.
The carrying and fair values of the Corporation's consolidated long-term debt
and preference shares are as follows.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Instruments (Unaudited)
As at
-------------------------------------------------------------------------
September 30, 2008 December 31, 2007
-------------------------------------------------------------------------
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
-------------------------------------------------------------------------
Long-term debt,
including current
portion (1) 5,122 5,321 5,023 5,635
-------------------------------------------------------------------------
Preference shares,
classified as debt (2) 320 326 320 346
-------------------------------------------------------------------------
(1) Carrying value at September 30, 2008 is net of unamortized deferred
financing costs of $36 million (December 31, 2007 - $33 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
$326 million as at September 30, 2008 (December 31, 2007: carrying
value $122 million; fair value $107 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. As at
September 30, 2008, all of the Corporation's US$408 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 US dollar borrowings designated as hedges of
the Corporation's foreign net investments are recorded in comprehensive income.
As at September 30, 2008, the Corporation had approximately US$105 million in
foreign net investments remaining to be hedged.
The Corporation and its subsidiaries also hedge exposures to fluctuations in
interest rates, foreign exchange rates and natural gas commodity prices through
the use of derivative financial instruments. The Corporation and its
subsidiaries do not hold or issue derivative financial instruments for trading
purposes. The following table summarizes the valuation of the Corporation's
consolidated derivative financial instruments.
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Derivative Financial Instruments (Unaudited)
As at
-------------------------------------------------------------------------
September 30, 2008 December 31, 2007
-------------------------------------------------------------------------
(Liability) Term to Carrying Estimated Carrying Estimated
Asset maturity Number of Value Fair Value Value Fair Value
(years) Contracts ($ ($ ($ ($
millions) millions) millions) millions)
-------------------------------------------------------------------------
Interest
rate swaps 1 to 2 4 (1) (1) - -
-------------------------------------------------------------------------
Foreign
exchange
forward
contract 3 1 1 1 - -
-------------------------------------------------------------------------
Natural gas
derivatives:
-------------------------------------------------------------------------
Swaps and
options Up to 3 245 (58) (58) (79) (79)
-------------------------------------------------------------------------
Gas
purchase
contract
premiums less 108 (3) (3) 5 5
than 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Two of the four 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. The effective portion of changes in the value of the interest rate swaps
at Fortis Properties is recorded in comprehensive income. The remaining
interest rate swaps are held by the Terasen Gas companies. The interest rate
swaps are designated as hedges of cash flow risk related to floating-rate debt
instruments.
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 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. At the Terasen Gas companies, changes in the fair
value of the interest rate swaps, 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 values of the natural gas derivatives were recorded in accounts
payable as at September 30, 2008 (December 31, 2007 - accounts payable and
accounts receivable).
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 Corporation 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 relevant market
information about the instruments. 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 September 30, 2008, 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
Changes in the Corporation's significant business risks during the nine months
ended September 30, 2008 from those disclosed in the Corporation's MD&A for the
year ended December 31, 2007 are described below.
Regulation: The PUC's June 2008 Final Decision on Belize Electricity's rate
application for the period July 1, 2008 through June 30, 2009 creates
uncertainty in the regulatory regime and the rate setting process in Belize.
The PUC ordered a BZ$36 million ($18 million; $13 million of which is the
Corporation's share) 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 allowed ROA to 10 per cent from 12 per cent.
The Final Decision violates both established regulatory practice and contractual
obligations made by the Government of Belize at the time Fortis made its initial
investment in Belize Electricity. On July 25, 2008, Belize Electricity filed
applications with the Supreme Court of Belize for leave to apply for judicial
review of 2008 amended bylaws, upon which the Final Decision was premised, and
appeal of the Final Decision. Leave was granted on October 3, 2008. It is
expected that the judicial review will be heard in late 2008.
Counterparty risk: The Terasen Gas companies are exposed to credit risk in the
event of non-performance by counterparties to derivative 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 international
government intervention in the banking systems, the Terasen Gas companies have
further limited the financial counterparties that 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.
Capital Resources: The recent volatility experienced in the global capital
markets may increase the cost of and timing of issuance of long-term capital by
the Corporation and its subsidiaries. Capital market volatility may also impact
the Corporation's and subsidiaries' future funding obligations and/or pension
expense associated with their defined benefit pension plans.
Environment: In 2008, the Government of British Columbia introduced changes to
energy policy including greenhouse gas emission reduction targets and a
consumption tax on carbon based fuels that impacts the competitiveness of
natural gas versus non-carbon based energy sources.
Integration of Terasen: Management considers the integration of Terasen within
the Fortis Group to be substantially complete and, therefore, the risk related
to integration has been reduced.
Labour Relations: In July 2008, Belize Electricity and the Belize Energy
Workers' Union, through a process of conciliation, entered into a new collective
agreement, which provided for retroactive wage increases of 2.5 per cent,
effective for each of June 1, 2006 and June 1, 2007, in addition to wage
increases of 2 per cent and 1 per cent, effective June 1, 2008 and June 1, 2009,
respectively. Reaching a new collective agreement concluded a negotiation and
subsequent conciliation process that commenced in 2006. The next review of the
collective agreement will be in 2011.
Newfoundland Power has two collective agreements governing its unionized
employees represented by the International Brotherhood of Electrical Workers,
Local 1620. Both contracts expired September 30, 2008 and contract renewal
negotiations commenced in October 2008.
CHANGES IN ACCOUNTING STANDARDS
Inventories: Effective January 1, 2008, the Corporation adopted the new Canadian
Institute of Chartered Accountants ("CICA") Handbook Section 3031 - Inventories.
The new standard requires inventories to be measured at the lower of cost or
net realizable value; disallows the use of a last-in first-out inventory-costing
methodology; and requires that, when circumstances which previously caused
inventories to be written down below cost or net realizable value no longer
exist, the amount of the write down is to be reversed. As at December 31, 2007,
inventories of $26 million were reclassified to utility capital assets from
inventory on the balance sheet as they were held for the development,
construction, maintenance and repair of utility capital assets. This new
standard did not have a material impact on the Corporation's earnings, cash flow
or financial position.
Capital Disclosures: Effective January 1, 2008, the Corporation adopted the new
CICA Handbook Section 1535 - Capital Disclosures. The new standard requires
additional information to be disclosed in the Notes to the consolidated
financial statements about the Corporation's capital and the manner in which it
is managed. The additional disclosures include quantitative and qualitative
information regarding the Corporation's objectives, policies and processes for
managing capital. This new standard did not have a material impact on the
Corporation's earnings, cash flow or financial position. The additional
required disclosures are provided in Note 16 to the Corporation's unaudited
interim consolidated financial statements for the three and nine months ended
September 30, 2008.
Disclosure and Presentation of Financial Instruments: Effective January 1, 2008,
the Corporation adopted new accounting recommendations for disclosure and
presentation of financial instruments provided in Sections 3862 and 3863 of the
CICA Handbook. The new recommendations require disclosures of both qualitative
and quantitative information that enables users of financial statements to
evaluate the nature and extent of risks from financial instruments to which the
Corporation is exposed. The new standards did not have a material impact on the
Corporation's earnings, cash flow or financial position. The additional
required disclosures are provided in Notes 17 and 18 to the Corporation's
unaudited interim consolidated financial statements for the three and nine
months ended September 30, 2008.
FUTURE ACCOUNTING PRONOUNCEMENTS
International Financial Reporting Standards ("IFRS"): In February 2008, the
Accounting Standards Board ("AcSB") confirmed that the use of IFRS will be
required in 2011 for publicly accountable enterprises in Canada. In April 2008,
the AcSB issued an IFRS Omnibus Exposure Draft proposing that publicly
accountable enterprises be required to apply IFRS, in full and without
modification, on January 1, 2011. The 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 the opening balance
sheet as at January 1, 2010. The AcSB proposes that CICA Handbook Section -
Accounting Changes, paragraph 1506.30, 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 of the adoption of IFRS and, at this time, the impact on
future financial position and results of operations is not reasonably
determinable or estimable. Further, Fortis anticipates a significant increase
in disclosure resulting from the adoption of IFRS and is continuing to assess
the level of disclosure required and any necessary system changes to gather and
process the information.
Fortis commenced its IFRS conversion project in 2007 and has established a
formal project governance structure. Regular reporting will occur to the Audit
Committee of the Board of Directors of Fortis and of the subsidiaries, where
appropriate. An external expert advisor has been engaged to assist in the IFRS
conversion project.
The Fortis IFRS conversion project consists of three phases: scoping and
diagnostic, analysis and development, and implementation and review. Phase One
has been completed which involved project planning and staffing and
identification of differences between current Canadian GAAP and IFRS. Currently,
the identified areas of accounting difference of highest potential impact to
Fortis are rate-regulated operations, property plant and equipment, investment
property, intangible assets, 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 IFRS.
Phase Two, currently in progress, involves completion of 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; and development of required solutions to
address identified issues.
It is anticipated that the adoption of IFRS will have an impact on current and
future system requirements. The degree of this impact is not reasonably
determinable at this stage of the project.
During the nine months ended September 30, 2008, several regulatory authorities
with jurisdiction over the Corporation's regulated utilities have begun their
own IFRS projects to determine the nature of any changes that should be made in
regulatory accounting requirements in response to IFRS. The Corporation's
regulated utilities will work with their respective regulatory authority to
identify transitional issues and suggest how those issues might be addressed.
Fortis will continue to review all proposed and continuing projects of the
International Accounting Standards Board, closely monitor any International
Financial Reporting Interpretations Committee initiatives with the potential to
impact rate-regulated accounting under IFRS, and will participate in any related
processes, as appropriate.
Rate-Regulated Operations: In March 2007, the AcSB issued an Exposure Draft on
rate-regulated operations that proposed: (i) the temporary exemption in Section
1100, Generally Accepted Accounting Principles, of the CICA Handbook 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 be removed; (ii) the explicit guidance for rate-regulated
operations provided in 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, be removed; and
(iii) Accounting Guideline 19, Disclosures by Entities Subject to Rate
Regulation ("AcG-19"), be retained as is.
In August 2007, the AcSB issued a Decision Summary on the Exposure Draft that
supported the removal of the temporary exemption in Section 1100, Generally
Accepted Accounting Principles, and the amendment to Section 3465, Income Taxes,
to recognize future income tax liabilities and assets as well as offsetting
regulatory assets and liabilities by entities subject to rate regulation. Both
changes will apply prospectively for fiscal years beginning on or after January
1, 2009. The AcSB also decided that the current guidance for rate-regulated
operations pertaining to property, plant and equipment, disposal of long-lived
assets and discontinued operations, and consolidated financial statements be
maintained, and that the existing AcG-19 will not be withdrawn from the CICA
Handbook but that the guidance will be updated as a result of the other changes.
The AcSB also decided that the final Background Information and Basis for
Conclusions associated with its rate-regulation project would not express any
views of the AcSB regarding the status of US Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation, as
"another source of GAAP" within the Canadian GAAP hierarchy.
Effective January 1, 2009, the impact on Fortis of the amendment to Section
3465, Income Taxes, will be the recognition of future income tax assets and
liabilities and related regulatory liabilities and assets for the amount of
future income taxes expected to be refunded to, or recovered from, customers in
future gas and electricity rates. Currently, the Terasen Gas companies,
FortisAlberta, FortisBC and Newfoundland Power use the taxes payable method of
accounting for income taxes. The effect on the Corporation's interim unaudited
consolidated financial statements, if it had adopted amended Section 3465,
Income Taxes, as at September 30, 2008, would have been an increase in future
income tax assets and future income tax liabilities of $28 million and $473
million, respectively, and a corresponding increase in regulatory liabilities
and regulatory assets of $28 million and $473 million, respectively. Included
in the amounts are the future income tax effects of the subsequent settlement of
the related regulatory assets and liabilities through customer rates, and the
separate disclosure of future income tax assets and liabilities that are
currently not recognized. Fortis is continuing to assess and monitor any
additional implications on its financial reporting related to accounting for
rate-regulated operations.
Goodwill and Intangible Assets: Effective January 1, 2009, the Corporation will
be adopting 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. The provisions related to the definition and initial recognition of
intangible assets, including internally generated intangible assets, are
equivalent to the corresponding provisions of International Accounting Standard
38, Intangible Assets. The Corporation is continuing to assess the financial
reporting impact of adopting this standard.
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 nine months ended
September 30, 2008 from those disclosed in the Corporation's MD&A for the year
ended December 31, 2007.
Contingencies: Fortis is subject to various legal proceedings and claims that
arise in the ordinary course of business operations. Management believes that
the amount of liability, if any, from these actions would not have a material
effect on the Corporation's financial position or results of operations. There
were no material changes in the Corporation's contingent liabilities during the
nine months ended September 30, 2008 from those disclosed in the MD&A for the
year ended December 31, 2007, except as discussed below.
Pursuant to a settlement agreement between FortisAlberta and Her Majesty the
Queen in Right of Alberta (the "Crown"), a Discontinuance of Action was filed on
September 10, 2008 in the Court of Queen's Bench of Alberta in the Judicial
District of Edmonton in relation to a March 24, 2006 statement of claim wherein
the Crown claimed that FortisAlberta was responsible for a fire that occurred in
October 2003 in an area of the Province of Alberta commonly referred to as "Poll
Haven Community Pasture". Payment of the settlement funds was covered by the
terms of an insurance contract between FortisAlberta and its insurer.
QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended December 31, 2006 through September 30, 2008. 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, revenues 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 2007 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.
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Fortis Inc.
Summary of Quarterly Results (Unaudited)
--------------------------------------------------------------------------
Net Earnings
Revenue and Applicable to Earnings per
Equity Income Common Shares Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
--------------------------------------------------------------------------
September 30, 2008 727 49 0.31 0.31
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June 30, 2008 848 29 0.19 0.18
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March 31, 2008 1,146 91 0.58 0.55
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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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June 30, 2007 566 41 0.31 0.27
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March 31, 2007 483 42 0.38 0.35
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December 31, 2006 393 34 0.33 0.32
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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. Given the diversified group of companies,
seasonality may vary. Financial results from May 17, 2007 were impacted by the
acquisition of Terasen. Virtually all 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,
Newfoundland Power's earnings in 2008 will be 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 will not be impacted by
the shift in the quarterly distribution of annual purchased power expense.
Financial results from August 1, 2007 were impacted by the acquisition of the
Delta Regina in Saskatchewan and from November 1, 2006 were impacted by the
acquisition of four hotels in western Canada. Financial results from January 1,
2007 were impacted by the consolidation of an approximate 54 per cent
controlling interest in Caribbean Utilities. The Corporation's previous
approximate 37 per cent interest in Caribbean Utilities was accounted for on an
equity basis.
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 this 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 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.
June 30, 2008/June 30, 2007 - Net earnings applicable to common shares were $29
million, or $0.19 per common share for the second quarter of 2008, compared to
earnings of $41 million, or $0.31 per common share, for the second quarter of
2007. Second quarter results for 2008 included a $13 million, or $0.08 per
common share, charge representing the Corporation's approximate 70 per cent
share of disallowed previously incurred fuel and purchased power costs at Belize
Electricity, and included a $2 million one-time charge at FortisOntario
associated with repayment of interconnection agreement amounts received in the
fourth quarter of 2007. Excluding the above one-time items, earnings for the
second quarter were $44 million compared to $41 million for the same quarter
last year. Earnings were favourably impacted by a full quarter of earnings'
contribution from the Terasen Gas companies, higher earnings at Newfoundland
Power associated with a shift in the quarterly distribution of annual purchased
power expense, increased non-regulated hydroelectric production and improved
performance at Fortis Properties. Partially offsetting those items were lower
earnings at FortisAlberta associated with higher corporate income taxes and
higher corporate financing costs associated with the Terasen acquisition.
March 31, 2008/March 31, 2007 - Net earnings applicable to common shares were
$91 million, or $0.58 per common share, for the first quarter of 2008, up $49
million from earnings of $42 million, or $0.38 per common share, for the first
quarter of 2007. Growth in earnings was primarily attributable to the
contribution from the Terasen Gas companies, acquired on May 17, 2007, and also
reflected improved performance at Caribbean Utilities. The growth was partially
offset by higher corporate financing costs associated with the Terasen
acquisition and lower earnings at Newfoundland Power associated with a shift in
the quarterly distribution of annual purchased power expense. Earnings'
contribution from Caribbean Utilities during the first quarter of 2007 was
reduced by $2 million associated with a charge on the disposal of steam-turbine
assets.
December 31, 2007/December 31, 2006 - Net earnings applicable to common shares
were $79 million, or $0.51 per common share, for the fourth quarter of 2007
compared to earnings of $34 million, or $0.33 per common share, for the fourth
quarter of 2006. The increase in earnings was driven by the contribution from
the Terasen Gas companies, including a $7 million after-tax gain on the sale of
surplus land, partially offset by increased corporate costs driven by Terasen
acquisition-related finance charges. Fourth quarter 2007 results also included
a one-time gain at FortisOntario related to a refund received associated with an
interconnection agreement.
OUTLOOK
The Corporation's principal businesses of regulated gas and electricity
distribution are capital intensive. Over the next five years, the Corporation's
consolidated capital program is expected to exceed $4.5 billion, with
approximately $3.5 billion to be driven by FortisAlberta, FortisBC and the
Corporation's regulated utility operations in the Caribbean. Gross gas utility
capital expenditures are expected to exceed $1 billion. The Corporation's
capital program should drive growth in earnings.
With Terasen now substantially integrated into the Fortis Group of Companies,
Fortis is well positioned to pursue acquisitions for profitable growth, focusing
on opportunities to acquire regulated natural gas and electric utilities in
Canada, the United States and the Caribbean. Fortis will also pursue growth in
its non-regulated businesses in support of its regulated utility growth
strategy.
OUTSTANDING SHARE DATA
As at October 30, 2008, the Corporation had issued and outstanding 157.3 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.
In October 2008, S&P removed Fortis from the S&P/TSX Completion and Equity
Completion indices and placed Fortis in the S&P/TSX 60, 60 Capped and Equity 60
indices.
The number of Common Shares of Fortis that would be issued if all outstanding
share options, convertible debt and First Preference Shares, Series C and E were
converted as at October 30, 2008 is as follows:
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Fortis Inc.
Conversion of Securities into Common Shares
As at October 30, 2008 (Unaudited)
-------------------------------------------------------------------------
Security Number of Common Shares (millions)
-------------------------------------------------------------------------
Stock Options 4.2
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Convertible Debt 1.4
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First Preference Shares, Series C 5.0
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First Preference Shares, Series E 7.9
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Total 18.5
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Additional information, including the Fortis 2007 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and nine months ended September 30, 2008 and 2007
(Unaudited)
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30 December 31
2008 2007
---------------------------------------------------------------------------
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ASSETS
Current assets
Cash and cash equivalents $68 $58
Accounts receivable 458 635
Prepaid expenses 26 19
Regulatory assets (Note 6) 133 119
Inventories of gas, materials and supplies 308 207
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993 1,038
Deferred charges and other assets 215 179
Regulatory assets (Note 6) 177 193
Future income taxes 40 37
Utility capital assets 7,124 6,748
Income producing properties 519 519
Intangibles, net of amortization 10 15
Goodwill 1,559 1,544
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$10,637 $10,273
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 18) $440 $475
Accounts payable and accrued charges 705 793
Dividends payable 42 43
Income taxes payable 49 30
Regulatory liabilities (Note 6) 18 20
Current installments of long-term debt and
capital lease obligations (Note 7) 377 436
Future income taxes 14 7
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1,645 1,804
Deferred credits 275 261
Regulatory liabilities (Note 6) 389 372
Future income taxes 60 55
Long-term debt and capital lease obligations
(Note 7) 4,780 4,623
Non-controlling interest 130 115
Preference shares 320 320
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7,599 7,550
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Shareholders' equity
Common shares (Note 8) 2,153 2,126
Preference shares (Note 9) 347 122
Contributed surplus 8 6
Equity portion of convertible debentures 5 6
Accumulated other comprehensive loss (Note 11) (77) (88)
Retained earnings 602 551
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3,038 2,723
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$10,637 $10,273
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Contingent liabilities and commitments (Note 19)
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2008 2007 2008 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating revenues $727 $651 $2,721 $1,700
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Expenses
Energy supply costs 320 272 1,427 729
Operating 174 172 535 426
Amortization 86 75 255 194
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580 519 2,217 1,349
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Operating income 147 132 504 351
Finance charges (Note 13) 89 91 270 206
---------------------------------------------------------------------------
Earnings before corporate taxes and
non-controlling interest 58 41 234 145
Corporate taxes (Note 14) - 2 48 15
---------------------------------------------------------------------------
Net earnings before non-controlling
interest 58 39 186 130
Non-controlling interest 4 6 8 11
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Net earnings 54 33 178 119
Preference share dividends 5 2 9 5
---------------------------------------------------------------------------
Net earnings applicable to common shares $49 $31 $169 $114
---------------------------------------------------------------------------
Earnings per common share (Note 8)
Basic $0.31 $0.20 $1.08 $0.86
Diluted $0.31 $0.20 $1.06 $0.79
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See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Retained Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2008 2007 2008 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Balance at beginning of period $592 $513 $551 $486
Net earnings applicable to common shares 49 31 169 114
---------------------------------------------------------------------------
641 544 720 600
Dividends on common shares (39) (33) (118) (89)
---------------------------------------------------------------------------
Balance at end of period $602 $511 $602 $511
---------------------------------------------------------------------------
---------------------------------------------------------------------------
See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Nine
Quarter Ended Months Ended
2008 2007 2008 2007
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--------------------------------------------------------------------------
Net earnings $54 $33 $178 $119
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Unrealized foreign currency translation gains
(losses) on net investments in
self-sustaining foreign operations 22 (29) 35 (70)
(Losses) gains on hedges of net investments
in self-sustaining foreign operations (17) 26 (28) 47
Corporate tax recovery (expense) 2 (4) 4 (8)
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Change in unrealized foreign currency
translation gains (losses),
net of hedging activities and tax (Note 11) 7 (7) 11 (31)
--------------------------------------------------------------------------
Comprehensive income $61 $26 $189 $88
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See accompanying Notes to interim consolidated financial statements.
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Nine
Quarter Ended Months Ended
2008 2007 2008 2007
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Operating Activities
Net earnings $54 $33 $178 $119
Items not affecting cash
Amortization - utility capital assets and
income producing properties 85 73 248 187
Amortization - intangibles and other 1 2 7 7
Future income taxes 2 2 17 2
Non-controlling interest 4 6 8 11
Write down of deferred power costs -
Belize Electricity (Note 6) - - 18 -
Other (2) 8 (6) 11
Change in long-term regulatory assets and
liabilities (13) 22 (3) 14
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131 146 467 351
Change in non-cash operating working capital (114) (87) (18) (130)
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17 59 449 221
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Investing Activities
Change in deferred charges, other assets
and deferred credits (15) (2) (32) (5)
Utility capital expenditures (231) (212) (612) (539)
Contributions in aid of construction 28 16 60 55
Income-producing property capital
expenditures (3) (4) (11) (10)
Proceeds on sale of capital assets 2 - 18 3
Business acquisitions - (50) - (1,303)
--------------------------------------------------------------------------
(219) (252) (577)(1,799)
--------------------------------------------------------------------------
Financing Activities
Change in short-term borrowings 160 99 (36) 29
Proceeds from long-term debt, net of issue
costs - 390 659 533
Repayments of long-term debt and capital
lease obligations (15) (15) (220) (48)
Net borrowings (repayments) under
committed credit facilities 103 (261) (374) (79)
Advances from (to) non-controlling interest 4 (1) 4 (3)
Issue of common shares 5 8 16 1,262
Issue of preference shares - - 223 -
Dividends
Common shares (39) (33) (118) (89)
Preference shares (5) (2) (9) (5)
Subsidiary dividends paid to
non-controlling interest (2) (3) (7) (9)
--------------------------------------------------------------------------
211 182 138 1,591
--------------------------------------------------------------------------
Effect of exchange rate changes on cash and
cash equivalents - (1) - (3)
--------------------------------------------------------------------------
Change in cash and cash equivalents 9 (12) 10 10
Cash and cash equivalents, beginning of period 59 63 58 41
--------------------------------------------------------------------------
Cash and cash equivalents, end of period $68 $51 $68 $51
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to interim consolidated financial statements.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2008 and 2007 (unless
otherwise stated)
(Unaudited)
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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 operating 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 operating segment operates as an
autonomous unit, assumes profit and loss responsibility and is accountable for
its own resource allocation.
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"), which Fortis
acquired through the acquisition of Terasen Inc. ("Terasen") on May 17, 2007.
TGI is the largest distributor of natural gas in British Columbia, serving
approximately 828,200 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 approximately 93,600 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 propane distribution system in Whistler, British
Columbia, providing service to approximately 2,400 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, serving
approximately 456,800 customers.
b. FortisBC: Includes FortisBC Inc., an integrated electric utility operating in
the southern interior of British Columbia, serving approximately 155,000
customers. FortisBC Inc. owns four hydroelectric generating plants 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 450-MW Waneta hydroelectric
generating facility owned by Teck Cominco Metals Ltd., the 149-MW Brilliant
Hydroelectric Plant 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, serving more than 234,000 customers. Newfoundland
Power has an installed generating capacity of approximately 139 MW, of which 96
MW is hydroelectric generation.
d. Other Canadian: Includes Maritime Electric and FortisOntario. Maritime
Electric is the principal distributor of electricity on Prince Edward Island,
serving approximately 73,000 customers. Maritime Electric also maintains
on-Island generating facilities with a combined capacity of 150 MW.
FortisOntario provides an integrated electric utility service to approximately
52,000 customers in Fort Erie, Cornwall, Gananoque and Port Colborne in Ontario.
FortisOntario operations primarily include Canadian Niagara Power Inc.
("Canadian Niagara Power") and Cornwall Street Railway, Light and Power Company,
Limited ("Cornwall Electric"). 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 10-year lease
agreement expiring in April 2012.
Regulated Electric Utilities - Caribbean
a. Belize Electricity: Belize Electricity is the principal distributor of
electricity in Belize, Central America, serving approximately 73,900 customers.
The Company has an installed generating capacity of 36 MW. Fortis holds an
approximate 70 per cent controlling interest in Belize Electricity.
b. Caribbean Utilities: Caribbean Utilities is the sole provider of electricity
on Grand Cayman, Cayman Islands, serving over 24,000 customers. The Company has
an installed generating capacity of approximately 137 MW. Fortis has an
approximate 57 per cent controlling ownership interest in Caribbean Utilities.
Caribbean Utilities is a public company traded on the Toronto Stock Exchange
(TSX:CUP.U). Caribbean Utilities had an April 30 fiscal year end whereby, 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. Caribbean Utilities has changed its fiscal year end to
December 31 which will result in the Corporation consolidating five months of
financial results of Caribbean Utilities during the fourth quarter of 2008.
Going forward, this will eliminate the previous two-month lag in consolidating
Caribbean Utilities' financial results.
c. P.P.C. Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.
(collectively referred to as Fortis Turks and Caicos): Fortis Turks and Caicos
is the principal distributor of electricity on the Turks and Caicos Islands,
serving more than 9,000 customers. The Company has a combined diesel-fired
generating capacity of 48 MW.
Non-Regulated - Fortis Generation
a. Belize: Operations consist of the 25-MW Mollejon and 7-MW Chalillo
hydroelectric generating facilities in Belize. All of the facilities' output is
sold to Belize Electricity under a 50-year power purchase agreement expiring in
2055.
b. Ontario: Includes 75 MW of water-right entitlement associated with the
Niagara Exchange Agreement, which expires April 30, 2009, 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.
c. Central Newfoundland: Through the Exploits River Hydro Partnership ("Exploits
Partnership"), a partnership between the Corporation, through its wholly owned
subsidiary Fortis Properties, and Abitibi-Consolidated Company of Canada
("Abitibi-Consolidated"), 36 MW of additional capacity was developed and
installed at two of Abitibi-Consolidated's hydroelectric generating plants in
central Newfoundland. Fortis Properties holds directly a 51 per cent interest in
the Exploits Partnership and Abitibi-Consolidated holds the remaining 49 per
cent interest. The Exploits Partnership sells its output to Newfoundland and
Labrador Hydro Corporation under a 30-year power purchase agreement expiring in
2033.
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.
Non-Regulated - Fortis Properties
Fortis Properties owns and operates 19 hotels with more than 3,500 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 includes finance
charges, including interest on debt incurred directly by Fortis and Terasen Inc.
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, 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. TES expects to increase its
activities in the development, building, owning and operating of innovative
geoexchange energy systems, community piping and energy transfer systems to
harness renewable energy sources. TES is entering into agreements with
developers to provide alternative thermal energy systems for both residential
and commercial development projects in British Columbia.
2. BASIS OF PRESENTATION
These interim consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("Canadian GAAP") for
interim financial statements and do not include all of the disclosures normally
found in the Corporation's Annual Consolidated Financial Statements. These
interim consolidated financial statements should be read in conjunction with the
Corporation's 2007 Annual 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.
Virtually all of the annual earnings of the Terasen Gas companies are generated
in the first and fourth quarters due to seasonality of the business, as a major
portion of gas distributed is used for space heating. Given the diversified
group of companies, seasonality may vary.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance
with Canadian GAAP, including selected accounting treatments that differ from
those used by entities not subject to rate regulation.
The timing of the recognition of certain assets, liabilities, revenues and
expenses, as a result of regulation, may differ from that otherwise expected
using Canadian GAAP for entities not subject to rate regulation. The differences
and nature of regulation are disclosed in Notes 2 and 4 to the Corporation's
2007 Annual Consolidated Financial Statements. These interim consolidated
financial statements have been prepared following the same accounting policies
and methods as those used in preparing the Corporation's 2007 Annual
Consolidated Financial Statements except as described below. All amounts are
presented in Canadian dollars unless otherwise stated.
Effective January 1, 2008, the Corporation adopted the following new accounting
standards issued by the Canadian Institute of Chartered Accountants ("CICA").
Inventories
Section 3031, Inventories, requires inventories to be measured at the lower of
cost or net realizable value; disallows the use of a last-in first-out
inventory-costing methodology; and requires that, when circumstances which
previously caused inventories to be written down below cost or net realizable
value no longer exist, the amount of the write-down is to be reversed. As at
December 31, 2007, inventories of $26 million were reclassified to utility
capital assets from inventory on the balance sheet as they were held for the
development, construction, maintenance and repair of other utility capital
assets. These inventories will be amortized when put in service using the
straight-line method based on estimated service lives of the utility capital
assets to which they are added. During the three and nine months ended September
30, 2008, inventories of $157 million and $850 million, respectively, were
expensed and reported in energy supply costs in the interim consolidated
statement of earnings ($118 million and $191 million for the three and nine
months ended September 30, 2007, respectively. Inventories expensed and reported
in energy supply costs for the nine months ended September 30, 2007 reflected
only 41/2 months of such expenses of the Terasen Gas companies, which were
acquired on May 17, 2007). Inventories expensed to operating expenses were $1
million and $3 million for the three and nine months ended September 30, 2008,
respectively ($1 million and $4 million for the three and nine months ended
September 30, 2007, respectively).
Capital Disclosures
Section 1535, Capital Disclosures, requires the Corporation to disclose
additional information about its capital and the manner in which it is managed.
The additional disclosures include quantitative and qualitative information
regarding the Corporation's objectives, policies and processes for managing
capital. The new disclosures are provided in Note 16.
Disclosure and Presentation of Financial Instruments
Section 3862, Financial Instruments - Disclosures, and Section 3863, Financial
Instruments - Presentation, require disclosures of both qualitative and
quantitative information that enables users of financial statements to evaluate
the nature and extent of risks from financial instruments to which the
Corporation is exposed. The new disclosures are provided in Notes 17 and 18.
4. FUTURE ACCOUNTING POLICIES
International Financial Reporting Standards ("IFRS")
In February 2008, the Accounting Standards Board ("AcSB") confirmed that the use
of IFRS will be required in 2011 for publicly accountable enterprises in Canada.
In April 2008, the AcSB issued an IFRS Omnibus Exposure Draft proposing that
publicly accountable enterprises be required to apply IFRS, in full and without
modification, on January 1, 2011. The 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 the opening balance
sheet as at January 1, 2010.
The AcSB proposes that CICA Handbook Section - Accounting Changes, paragraph
1506.30, 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 of the adoption
of IFRS and, at this time, the impact on future financial position and results
of operations is not reasonably determinable or estimable. Further, Fortis
anticipates a significant increase in disclosure resulting from the adoption of
IFRS and is continuing to assess the level of disclosure required and any
necessary system changes to gather and process the information.
Rate-Regulated Operations
In March 2007, the AcSB issued an Exposure Draft on rate-regulated operations
that proposed: (i) the temporary exemption in Section 1100, Generally Accepted
Accounting Principles, of the CICA Handbook 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 be
removed; (ii) the explicit guidance for rate-regulated operations provided in
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, be removed; and (iii) Accounting
Guideline 19, Disclosures by Entities Subject to Rate Regulation ("AcG-19"), be
retained as is.
In August 2007, the AcSB issued a Decision Summary on the Exposure Draft that
supported the removal of the temporary exemption in Section 1100, Generally
Accepted Accounting Principles, and the amendment to Section 3465, Income Taxes,
to recognize future income tax liabilities and assets as well as offsetting
regulatory assets and liabilities by entities subject to rate regulation. Both
changes will apply prospectively for fiscal years beginning on or after January
1, 2009. The AcSB also decided that the current guidance for rate-regulated
operations pertaining to property, plant and equipment, disposal of long-lived
assets and discontinued operations, and consolidated financial statements be
maintained, and that the existing AcG-19 will not be withdrawn from the CICA
Handbook but that the guidance will be updated as a result of the other changes.
The AcSB also decided that the final Background Information and Basis for
Conclusions associated with its rate-regulation project would not express any
views of the AcSB regarding the status of US Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation, as
"another source of GAAP" within the Canadian GAAP hierarchy.
Effective January 1, 2009, the impact on Fortis of the amendment to Section
3465, Income Taxes, will be the recognition of future income tax assets and
liabilities and related regulatory liabilities and assets for the amount of
future income taxes expected to be refunded to, or recovered from, customers in
future gas and electricity rates. Currently, the Terasen Gas companies,
FortisAlberta, FortisBC and Newfoundland Power use the taxes payable method of
accounting for income taxes. The effect on the Corporation's interim
consolidated financial statements, if it had adopted amended Section 3465,
Income Taxes, as at September 30, 2008, would have been an increase in future
income tax assets and future income tax liabilities of $28 million and $473
million, respectively, and a corresponding increase in regulatory liabilities
and regulatory assets of $28 million and $473 million, respectively. Included in
the amounts are the future income tax effects of the subsequent settlement of
the related regulatory assets and liabilities through customer rates, and the
separate disclosure of future income tax assets and liabilities that are
currently not recognized. Fortis is continuing to assess and monitor any
additional implications on its financial reporting related to accounting for
rate-regulated operations.
Goodwill and Intangible Assets
Effective January 1, 2009, the Corporation will be adopting 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.
The provisions related to the definition and initial recognition of intangible
assets, including internally generated intangible assets, are equivalent to the
corresponding provisions of International Accounting Standard 38, Intangible
Assets. The Corporation is continuing to assess the financial reporting impact
of adopting this standard.
5. 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 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 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 to the Corporation's
critical accounting estimates during the nine months ended September 30, 2008
from those disclosed in the Corporation's Management Discussion and Analysis for
the year ended December 31, 2007.
6. 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 in Note 4 to the Corporation's 2007 Annual Audited Consolidated
Financial Statements.
As at As at
September December
($ millions) 30, 2008 31, 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Regulatory Assets
Rate stabilization accounts - Terasen Gas companies (1) 47 99
Rate stabilization accounts - electric utilities (2) 79 55
Regulatory other post-employment benefit ("OPEB") asset 50 44
Income taxes recoverable on OPEB plans 17 16
Alberta Electric System Operator ("AESO") charges deferral 36 8
Deferred capital asset amortization 9 12
Weather normalization account 7 11
Residential unbundling 7 9
Deferred pension costs 7 8
Southern Crossing Pipeline tax reassessment 7 7
Energy management costs 7 6
Lease costs 6 5
Other regulatory assets 31 32
--------------------------------------------------------------------------
Total regulatory assets 310 312
Less: current portion (133) (119)
--------------------------------------------------------------------------
Long-term regulatory assets 177 193
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at As at
September 30, December 31,
($ millions) 2008 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Regulatory Liabilities
Future removal and site restoration provision 336 319
Unbilled revenue liability 17 22
Performance-based rate-setting incentive liabilities 13 14
Rate stabilization account - Terasen Gas companies (3) 5 -
Other regulatory liabilities 36 37
--------------------------------------------------------------------------
Total regulatory liabilities 407 392
Less: current portion (18) (20)
--------------------------------------------------------------------------
Long-term regulatory liabilities 389 372
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Rate stabilization asset accounts include the revenue deficiency
deferral account, revenue stabilization adjustment mechanism account
("RSAM"), commodity cost reconciliation account ("CCRA") and gas cost
variance account. At December 31, 2007, the rate stabilization
accounts also included the midstream cost reconciliation account
("MCRA"). The decrease in the rate stabilization asset accounts from
December 31, 2007 was mainly due to lower balances in the RSAM and
CCRA, as well as a shift in the balance of the MCRA to a payable
balance at September 30, 2008 from a receivable balance at December
31, 2007. The change in balances was a result of recording the change
in the fair market value of the natural gas derivative contracts.
(2) During the second quarter of 2008, a downward $18 million adjustment
was made to Belize Electricity's cost of power rate stabilization
account reflecting, in substance, the disallowance of previously
incurred fuel and purchased power costs as a result of the Final
Decision by the Public Utilities Commission ("PUC") of Belize on
Belize Electricity's 2008/2009 rate application. On July 25, 2008,
Belize Electricity filed applications with the Supreme Court of
Belize for leave to apply for judicial review of 2008 amended bylaws,
upon which the Final Decision was premised, and appeal of the Final
Decision. Leave was granted on October 3, 2008.
(3) Rate stabilization liability account relates to the MCRA.
7. LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS
As at As at
September 30, December 31,
($ millions) 2008 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Long-term debt and capital lease obligations 5,037 4,562
Long-term classification of committed credit
facilities (Note 18) 156 530
Deferred debt financing costs (36) (33)
--------------------------------------------------------------------------
Total long-term debt and capital lease obligations 5,157 5,059
Less: Current installments of long-term debt
and capital lease obligations (377) (436)
--------------------------------------------------------------------------
4,780 4,623
--------------------------------------------------------------------------
--------------------------------------------------------------------------
In February 2008, TGVI issued $250 million 6.05% senior unsecured debentures,
maturing in February 2038. The net proceeds of the debenture offering were used
to repay committed credit-facility borrowings.
In April 2008, Maritime Electric issued $60 million 6.05% secured first mortgage
bonds, maturing in April 2038. The net proceeds were used to repay short-term
borrowings.
In April 2008, FortisAlberta issued $100 million 5.85% senior unsecured
debentures, maturing in April 2038. The net proceeds were used to repay
committed credit-facility borrowings.
In May 2008, TGI issued $250 million 5.80% senior unsecured debentures, maturing
in May 2038. The net proceeds of the debenture offering were primarily used to
repay maturing $188 million 6.20% debentures and short-term borrowings.
As at September 30, 2008, $16 million of Belize Electricity's debt was in
default with certain debt covenant financial ratios and waivers of the default
have not yet been obtained from the lenders. This debt was classified as current
in the consolidated balance sheet as at September 30, 2008 (Note 16).
8. COMMON SHARES
Authorized: an unlimited number of Common Shares without nominal or par
value.
As at As at
Issued and Outstanding September 30, 2008 December 31, 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Common Shares 157,303 2,153 155,521 2,126
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Common Shares issued during the period were as follows:
Quarter Ended September 30, Year-to-Date September 30,
2008 2008
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Opening balance 157,071 2,148 155,521 2,126
Conversion of
debentures - - 1,042 11
Consumer Share
Purchase Plan 25 1 68 2
Dividend Reinvestment
Plan 68 1 180 4
Employee Share Purchase
Plan 67 2 224 6
Stock Option Plans 72 1 268 4
--------------------------------------------------------------------------
Ending balance 157,303 2,153 157,303 2,153
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Earnings per Common Share
During the nine months ended September 30, 2008, holders of the Corporation's
6.75% and 5.50% unsecured subordinated convertible debentures converted
approximately US$11 million of the debentures into 1,041,871 Common Shares of
the Corporation.
The Corporation calculates earnings per common share on the weighted average
number of common shares outstanding. The weighted average number of common
shares outstanding was 157.2 million and 154.5 million for the quarters ended
September 30, 2008 and September 30, 2007, respectively, and was 156.9 million
and 131.6 million for the year-to-date periods ended September 30, 2008 and
September 30, 2007, respectively.
Diluted earnings per common share are calculated using the treasury stock method
for options and the "if-converted" method for convertible securities.
Earnings per common share are as follows:
Quarter Ended September 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Shares per
($ (in Common Earnings (in Common
millions) millions) Share($ millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net earnings
applicable
to common
shares 49 31
Weighted
average
shares
outstanding 157.2 154.5
---------------------------------------------------------------------------
Basic
Earnings per
Common Share $0.31 $0.20
---------------------------------------------------------------------------
Effect of
dilutive
securities:
Stock
options - 1.0 - 1.3
Preference
shares 4 12.8 4 11.5
Convertible
debentures 1 1.4 1 3.0
---------------------------------------------------------------------------
54 172.4 36 170.3
Deduct
anti-dilutive
impacts:
Preference
shares (4) (12.9) (4) (11.5)
Convertible
debentures (1) (1.4) (1) (2.1)
---------------------------------------------------------------------------
Diluted
Earnings per
Common Share 49 158.1 $0.31 31 156.7 $0.20
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date September 30
---------------------------------------------------------------------------
---------------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------------
Weighted Weighted
Average Earnings Average Earnings
Earnings Shares per Shares per
($ (in Common Earnings (in Common
millions) millions) Share($ millions) millions) Share
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net
earnings
applicable
to common
shares 169 114
Weighted
average
shares
outstanding 156.9 131.6
---------------------------------------------------------------------------
Basic
Earnings per
Common Share $1.08 $0.86
---------------------------------------------------------------------------
Effect of
dilutive
securities:
Subscription
receipts(1) - - - 10.4
Stock options - 1.0 - 1.3
Preference
shares 12 12.8 12 11.5
Convertible
debentures 2 2.2 2 3.2
---------------------------------------------------------------------------
183 172.9 128 158.0
Deduct
anti-dilutive
impacts:
Preference
shares - - (12) (11.5)
Convertible
debentures (2) (1.4) (2) (1.4)
---------------------------------------------------------------------------
Diluted
Earnings per
Common Share 181 171.5 $1.06 114 145.1 $0.79
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Dilution relates to the period the Subscription Receipts were
outstanding. The Subscription Receipts were outstanding from March 15,
2007 to May 16, 2007 and were converted into Common Shares on May 17,
2007.
9. PREFERENCE SHARES
On May 23, 2008, the Corporation issued 8 million 5.25% Five-Year Fixed Rate
Reset First Preference Shares, Series G ("First Preference Shares, Series G")
and on June 4, 2008 issued an additional 1.2 million First Preference Shares,
Series G, following the exercise in full of an over-allotment option in
connection with the offering of the 8 million of First Preference Shares, Series
G. The 9.2 million First Preference Shares, Series G were issued at $25.00 per
share for net after-tax proceeds of $225 million.
The holders of the First Preference Shares, Series G are entitled to receive
fixed cumulative preferential cash dividends in the amount of $1.3125 per share
per annum payable in quarterly installments up to and including August 31, 2013.
For each five-year period after that date, the holders of First Preference
Shares, Series G are entitled to receive fixed cumulative preferential cash
dividends in the amount per share per annum determined by multiplying the $25.00
per share by the annual fixed dividend rate, which is the sum of the five-year
Government of Canada Bond Yield on the applicable dividend reset date plus 2.13
per cent.
On September 1, 2013, and on September 1 every five years thereafter, the
Corporation may, at its option, redeem for cash the outstanding First Preference
Shares, Series G by the payment of $25.00 per share plus all accrued and unpaid
dividends.
As the First Preference Shares, Series G are not redeemable at the option of the
shareholder, they are classified as equity and the associated dividends are
deducted on the statement of earnings immediately before arriving at net
earnings applicable to common shares.
10. STOCK-BASED COMPENSATION PLANS
In February 2008, the Corporation granted 827,504 options on Common Shares under
its 2006 Stock Option Plan at the five-day volume weighted average trading price
immediately preceding the date of grant of $28.27. 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,
estimated using the Black-Scholes fair value option-pricing model, was $4.76 per
option.
In March 2008, 18,019 Performance Share Units ("PSUs"), formerly named
Restricted Share Units, were paid out to the President and CEO of the
Corporation at $28.36 per PSU, for a total of approximately $0.5 million. The
payout was made upon the three-year maturation period in respect of the PSU
grant which was made in March 2005 and the President and CEO satisfying the
payment requirements, as determined by the Human Resources Committee of the
Board of Directors of Fortis.
In February 2008, 32,940 PSUs were granted to the President and CEO of the
Corporation, which will mature in February 2011.
During the nine months ended September 30, 2008, 27,223 Deferred Share Units
were granted to the Corporation's directors representing the equity component of
their annual compensation and their annual retainers in lieu of cash.
At September 30, 2008, 4.2 million stock options were outstanding and 2.3
million stock options were vested.
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes unrealized foreign currency
translation gains and losses, net of hedging activities, gains and losses on
cash flow hedging activities and gains and losses on discontinued cash flow
hedging activities.
Quarter Ended
September 30, 2008
---------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) July 1 change September 30
---------------------------------------------------------------------
---------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains on net
investments in self-sustaining foreign
operations, net of after-tax hedging
activities (78) 7 (71)
Losses on derivative financial
instruments designated as cash flow
hedges, net of tax (1) - (1)
Net losses on derivative financial
instruments previously discontinued
as cash flow hedges, net of tax (5) - (5)
---------------------------------------------------------------------
Accumulated Other Comprehensive
(Loss) Income (84) 7 (77)
---------------------------------------------------------------------
---------------------------------------------------------------------
Quarter Ended
September 30, 2007
---------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) July 1 change September 30
---------------------------------------------------------------------
---------------------------------------------------------------------
Unrealized foreign currency
translation (losses) gains on net
investments in self-sustaining foreign
operations, net of after-tax hedging
activities (75) (7) (82)
Losses on derivative financial
instruments designated as cash flow
hedges, net of tax (1) - (1)
Net losses on derivative financial
instruments previously discontinued
as cash flow hedges, net of tax (5) - (5)
--------------------------------------------------------------------
Accumulated Other Comprehensive
(Loss) Income (81) (7) (88)
---------------------------------------------------------------------
---------------------------------------------------------------------
Year-to-date 2008
---------------------------------------------------------------------
Opening Ending
balance Net balance
($ millions) January 1 change September 30
---------------------------------------------------------------------
---------------------------------------------------------------------
Unrealized foreign
currency translation
(losses) gains on net
investments in
self-sustaining foreign
operations, net of after-
tax hedging activities (82) 11 (71)
Losses on derivative
financial instruments
designated as cash flow
hedges, net of tax (1) - (1)
Net losses on derivative
financial instruments
previously discontinued
as cash flow hedges, net
of tax (5) - (5)
---------------------------------------------------------------------
Accumulated Other
Comprehensive (Loss)
Income (88) 11 (77)
---------------------------------------------------------------------
---------------------------------------------------------------------
Year-to-date 2007
-----------------------------------------------------------------------
Opening Transition Ending
balance amount Net balance
($ millions) January 1 January 1 change September 30
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Unrealized foreign
currency translation
(losses) gains on net
investments in
self-sustaining foreign
operations, net of after-
tax hedging activities (51) - (31) (82)
Losses on derivative
financial instruments
designated as cash flow
hedges, net of tax - (1) - (1)
Net losses on derivative
financial instruments
previously discontinued
as cash flow hedges, net
of tax - (5) - (5)
-----------------------------------------------------------------------
Accumulated Other
Comprehensive (Loss)
Income (51) (6) (31) (88)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
12. EMPLOYEE FUTURE BENEFIT
The Corporation and each of its subsidiaries maintain one or more defined
benefit pension plans, defined contribution pension plans and group registered
retirement savings plans ("RRSPs") for their employees. The cost of providing
the defined benefit arrangements was $7 million for the quarter ended September
30, 2008 ($10 million for the quarter ended September 30, 2007) and $21 million
year-to-date September 30, 2008 ($21 million year-to-date September 30, 2007).
Recent capital market volatility may impact the Corporation's and subsidiaries'
future funding obligations and/or pension expense associated with their defined
benefit pension plans.
The cost of providing the defined contribution arrangements and group RRSPs for
the quarter ended September 30, 2008 was $3 million ($2 million for the quarter
ended September 30, 2007) and $8 million year-to-date September 30, 2008 ($7
million year-to-date September 30, 2007).
13. FINANCE CHARGES
Quarter Ended Year-to-date
September 30 September 30
($ millions) 2008 2007 2008 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest - Long-term debt and capital lease
obligations 79 81 244 185
- Short-term borrowings 11 8 24 16
Interest charged to construction (4) (2) (8) (5)
Interest earned (1) - (2) (2)
Dividends on preference shares classified
as debt 4 4 12 12
--------------------------------------------------------------------------
89 91 270 206
--------------------------------------------------------------------------
--------------------------------------------------------------------------
14. CORPORATE TAXES
Corporate taxes differ from the amount that would be expected to be generated by
applying the enacted Canadian federal and provincial statutory tax rates 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
September 30 September 30
(in millions, except as noted) 2008 2007 2008 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Weighted average Canadian federal and
provincial statutory income tax rates 33.4% 35.0% 32.1% 35.0%
--------------------------------------------------------------------------
Statutory income tax rates applied to
earnings before corporate taxes and
non-controlling interest $19 $14 $75 $51
Preference share dividends 1 1 4 4
Difference between Canadian statutory rates
and those applicable to foreign
subsidiaries(1) (5) (6) (7) (13)
Items capitalized for accounting but expensed
for income tax purposes (9) (6) (25) (20)
Difference between capital cost allowance
("CCA") and other deductions claimed for
income tax purposes, and amounts recorded
for accounting purposes(2) (2) (1) 3 (6)
Regulatory deferrals (3) 1 - 4 (2)
Quebec Trust tax settlement - Terasen (4) (7) - (7) -
Other 2 - 1 1
--------------------------------------------------------------------------
Corporate taxes $- $2 $48 $15
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Effective income tax rate N/A 4.9% 20.5% 10.3%
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Net losses at Belize Electricity during the nine months ended
September 30, 2008, as a result of a $13 million charge during the
second quarter of 2008 representing the Corporation's approximate 70
per cent share of $18 million of disallowed previously incurred fuel
and purchased power costs, had the effect of increasing effective
corporate tax rates for the nine months ended September 30, 2008
compared to the same period last year.
(2) During the nine months ended September 30, 2008, CCA deductions at
FortisAlberta were lower than amortization expense. However, during
the same period last year, CCA deductions at FortisAlberta were higher
than amortization expense. The higher CCA deductions last year were
required to offset taxable income on the sale, in 2007, of the 2006
AESO charges deferral receivable balance.
(3) As a result of using the taxes-payable method of accounting for income
taxes by the Terasen Gas companies, FortisBC and Newfoundland Power,
income tax on certain regulatory deferrals is not required to be
recorded when the costs are incurred. Rather, the income tax is
recorded when the costs are recovered from customers in future rates.
(4) During the third quarter of 2008, Terasen reached a settlement with
Revenu Quebec and Canada Revenue Agency related to amounts owing as a
result of amended Quebec tax legislation. The legislation was passed in
2006 for the purpose of challenging certain inter-provincial Canadian
tax structures. As a result of the settlement, Terasen recorded an
approximate $7.5 million tax reduction in the third quarter of 2008.
15. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Quarter Terasen
ended Gas Total
September Companies- Fortis Fortis NF Other Electric Electric
30, 2008 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating
revenues 271 74 52 94 66 286 96
Energy supply
costs 157 - 12 51 44 107 60
Operating
expenses 59 31 16 11 7 65 12
Amortization 24 22 8 11 4 45 8
---------------------------------------------------------------------------
Operating
income 31 21 16 21 11 69 16
Finance charges 33 10 7 8 4 29 4
Corporate taxes
(recoveries) (3) (6) 1 5 2 2 1
Non-controlling
interest - - - - - - 4
---------------------------------------------------------------------------
Net earnings
(loss) 1 17 8 8 5 38 7
Preference share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable
to common
shares 1 17 8 8 5 38 7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 139
Identifiable
assets 3,510 1,482 958 971 513 3,924 759
---------------------------------------------------------------------------
Total assets 4,419 1,709 1,179 971 576 4,435 898
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 56 78 31 17 11 137 31
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended Corporate Inter-
September 30, 2008 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Operating revenues 21 56 7 (10) 727
Energy supply costs 2 - - (6) 320
Operating expenses 3 33 2 - 174
Amortization 3 4 2 - 86
--------------------------------------------------------------------------
Operating income 13 19 3 (4) 147
Finance charges 2 6 19 (4) 89
Corporate taxes
(recoveries) 2 4 (6) - -
Non-controlling
interest - - - - 4
--------------------------------------------------------------------------
Net earnings (loss) 9 9 (10) - 54
Preference share
dividends - - 5 - 5
--------------------------------------------------------------------------
Net earnings (loss)
applicable
to common
shares 9 9 (15) - 49
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,559
Identifiable assets 262 537 115 (29) 9,078
--------------------------------------------------------------------------
Total assets 262 537 115 (29) 10,637
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures 6 3 1 - 234
--------------------------------------------------------------------------
--------------------------------------------------------------------------
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter ended
September 30, 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating
revenues 227 70 52 90 63 275 80
Energy supply
costs 118 - 15 59 41 115 42
Operating
expenses 56 31 16 12 7 66 11
Amortization 23 19 7 6 4 36 7
---------------------------------------------------------------------------
Operating
income 30 20 14 13 11 58 20
Finance charges 33 8 7 10 4 29 4
Corporate taxes
(recoveries) 1 (3) 1 1 2 1 -
Non-controlling
interest - - - - - - 6
---------------------------------------------------------------------------
Net (loss)
earnings (4) 15 6 2 5 28 10
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net (loss)
earnings
applicable
to common
shares (4) 15 6 2 5 28 10
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 907 227 221 - 63 511 127
Identifiable
assets 3,402 1,248 884 962 465 3,559 628
---------------------------------------------------------------------------
Total assets 4,309 1,475 1,105 962 528 4,070 755
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 50 66 36 21 11 134 23
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Quarter ended
September 30, 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Operating revenues 17 54 8 (10) 651
Energy supply costs 2 - - (5) 272
Operating expenses 3 32 5 (1) 172
Amortization 3 4 2 - 75
--------------------------------------------------------------------------
Operating income 9 18 1 (4) 132
Finance charges 2 6 21 (4) 91
Corporate taxes
(recoveries) 2 4 (6) - 2
Non-controlling
interest - - - - 6
--------------------------------------------------------------------------
Net (loss) earnings 5 8 (14) - 33
Preference share
dividends - - 2 - 2
--------------------------------------------------------------------------
Net (loss)
earnings
applicable
to common
shares 5 8 (16) - 31
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Goodwill - - - - 1,545
Identifiable assets 229 541 121 (19) 8,461
--------------------------------------------------------------------------
Total assets 229 541 121 (19) 10,006
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital
expenditures 4 4 1 - 216
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario
(2) Includes Belize Electricity, Caribbean Utilities,
and Fortis Turks and Caicos
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gas Utilities Electric Utilities
---------------------------------------------------------------------------
Year-to- Terasen
date Gas Total
September Companies- Fortis Fortis NF Other Electric Electric
30, 2008 Canadian Alberta BC Power Canadian Canadian Caribbean
($ millions) (1) (2) (3)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating
revenues 1,296 222 171 378 197 968 249
Energy supply
costs 850 - 45 243 133 421 164
Operating
expenses 182 96 49 38 21 204 35
Amortization 73 63 25 33 13 134 23
---------------------------------------------------------------------------
Operating
income 191 63 52 64 30 209 27
Finance charges 96 30 21 25 13 89 11
Corporate taxes
(recoveries) 24 (2) 4 15 6 23 1
Non-controlling
interest - - - - - - 6
---------------------------------------------------------------------------
Net earnings
(loss) 71 35 27 24 11 97 9
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net earnings
(loss)
applicable
to common
shares 71 35 27 24 11 97 9
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 909 227 221 - 63 511 139
Identifiable
assets 3,510 1,482 958 971 513 3,924 759
---------------------------------------------------------------------------
Total assets 4,419 1,709 1,179 971 576 4,435 898
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 152 222 81 47 28 378 65
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Corpo-
Year-to-date rate Inter-
September 30, 2008 Fortis Fortis and segment
($ millions) Generation Properties Other eliminations Consolidated
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating revenues 62 155 19 (28) 2,721
Energy supply costs 6 - - (14) 1,427
Operating expenses 11 99 8 (4) 535
Amortization 8 11 6 - 255
---------------------------------------------------------------------------
Operating income 37 45 5 (10) 504
Finance charges 6 18 60 (10) 270
Corporate taxes
(recoveries) 7 8 (15) - 48
Non-controlling
interest 2 - - - 8
---------------------------------------------------------------------------
Net earnings (loss) 22 19 (40) - 178
Preference share
dividends - - 9 - 9
---------------------------------------------------------------------------
Net earnings (loss)
applicable to common
shares 22 19 (49) - 169
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,559
Identifiable assets 262 537 115 (29) 9,078
---------------------------------------------------------------------------
Total assets 262 537 115 (29) 10,637
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 13 11 4 - 623
---------------------------------------------------------------------------
---------------------------------------------------------------------------
REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date
September 30, 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating
revenues 357 202 167 359 198 926 231
Energy supply
costs 191 - 48 239 132 419 127
Operating
expenses 84 90 49 39 21 199 39
Amortization 35 56 23 25 12 116 21
---------------------------------------------------------------------------
Operating income 47 56 47 56 33 192 44
Finance charges 48 26 19 26 13 84 11
Corporate taxes
(recoveries) 2 (12) 4 9 7 8 1
Non-controlling
interest - - - - - - 10
---------------------------------------------------------------------------
Net (loss)
earnings (3) 42 24 21 13 100 22
Preference
share
dividends - - - - - - -
---------------------------------------------------------------------------
Net (loss)
earnings
applicable
to common
shares (3) 42 24 21 13 100 22
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill 907 227 221 - 63 511 127
Identifiable
assets 3,402 1,248 884 962 465 3,559 628
---------------------------------------------------------------------------
Total assets 4,309 1,475 1,105 962 528 4,070 755
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 64 205 108 53 26 392 70
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NON-REGULATED
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Year-to-date
September 30, 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating revenues 56 141 16 (27) 1,700
Energy supply costs 6 - - (14) 729
Operating expenses 11 89 8 (4) 426
Amortization 8 10 4 - 194
---------------------------------------------------------------------------
Operating income 31 42 4 (9) 351
Finance charges 7 18 47 (9) 206
Corporate taxes
(recoveries) 6 8 (10) - 15
Non-controlling
interest 1 - - - 11
---------------------------------------------------------------------------
Net (loss) earnings 17 16 (33) - 119
Preference share
dividends - - 5 - 5
---------------------------------------------------------------------------
Net (loss) earnings
applicable to common
shares 17 16 (38) - 114
---------------------------------------------------------------------------
Goodwill - - - - 1,545
Identifiable assets 229 541 121 (19) 8,461
---------------------------------------------------------------------------
Total assets 229 541 121 (19) 10,006
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures 11 10 2 - 549
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) The Terasen Gas companies were acquired on May 17, 2007.
(2) Includes Maritime Electric and FortisOntario
(3) Includes Belize Electricity, Caribbean Utilities,
and Fortis Turks and Caicos
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
Regulated Electric Utilities - Caribbean and Other Canadian Electric Utilities,
electricity sales from Newfoundland Power to Fortis Properties and finance
charges on inter-segment borrowings. The significant inter-segment transactions
for the three and nine months ended September 30, 2008 and 2007 are as follows.
Inter-Segment Transactions Quarter Ended Year-to-date
September 30 September 30
($ millions) 2008 2007 2008 2007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Sales from Fortis Generation to Regulated
Electric Utilities Caribbean 6 4 13 12
Sales from Fortis Generation to Other
Canadian Electric Utilities - - 1 1
Sales from Newfoundland Power to Fortis
Properties 1 1 3 3
Inter-segment finance charges on borrowings
from:
Corporate to Regulated Electric Utilities -
Canadian - 1 1 2
Corporate to Regulated Electric Utilities -
Caribbean 1 - 3 1
Corporate to Fortis Properties 2 2 6 6
---------------------------------------------------------------------------
---------------------------------------------------------------------------
16. CAPITAL MANAGEMENT
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital in order to allow them to fund
maintenance and expansion of infrastructure. Wherever possible, Fortis raises
debt at the subsidiary level to ensure regulatory transparency, tax efficiency
and financing flexibility. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40
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 utility's
customer rates. Fortis generally finances a significant portion of acquisitions
with proceeds from common and preference share issues.
The consolidated capital structure of Fortis is presented in the following table.
As at As at
September 30, December 31,
2008 2007
($ ($
millions) (%) millions) (%)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total debt and capital lease
obligations (net of cash)(1) 5,529 62.2 5,476 64.3
Preference shares(2) 667 7.5 442 5.2
Common shareholders' equity 2,691 30.3 2,601 30.5
--------------------------------------------------------------------------
Total 8,887 100.0 8,519 100.0
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(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,
excluding preference shares, cannot exceed 70 per cent of the Corporation's
capital structure, as defined by the long-term debt agreements. As at September
30, 2008, the Corporation and its subsidiaries, except for Belize Electricity,
were in compliance with their debt covenants.
As a result of the PUC's Final Decision on Belize Electricity's 2008/2009 rate
application, Belize Electricity does not meet certain debt covenant financial
ratios resulting in approximately $16 million (BZ$30 million) of indebtedness
being in default as at September 30, 2008 and Belize Electricity being
prohibited from incurring new indebtedness or declaring dividends under certain
of these debt covenants. The Company has informed the lenders of the situation
and has requested appropriate waivers. As at September 30, 2008, the above debt
was classified as current in the consolidated balance sheet.
The Corporation's credit ratings and consolidated credit facilities are
discussed further under "Liquidity Risk" in Note 18.
17. FINANCIAL INSTRUMENTS
The Corporation has designated its consolidated non-derivative financial
instruments as follows:
As at As at
September 30, 2008 December 31, 2007
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Held for trading
Cash and cash equivalents (1) 68 68 58 58
Loans and receivables
Trade and other accounts
receivable (1) (2) (3) 457 457 630 630
Other receivables due from
customers (1) (3) (4) 8 8 7 7
Other financial liabilities
Short-term borrowings (1) (3) 440 440 475 475
Trade and other accounts payable
(1) (3) (5) 644 644 714 714
Dividends payable (1) (3) 42 42 43 43
Customer deposits (1) (3) (6) 6 6 5 5
Long-term debt, including current
portion (7) (8) 5,122 5,321 5,023 5,635
Preference shares, classified as
debt (7) (9) 320 326 320 346
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1)Due to the nature and/or short-term maturity of these financial
instruments, carrying value approximates fair value.
(2)Included in accounts receivable on the balance sheet
(3)Carrying value approximates amortized cost.
(4)Included in deferred charges and other assets on the balance sheet
(5)Included in accounts payable and accrued charges on the balance sheet
(6)Included in deferred credits on the balance sheet
(7)Carrying value is measured at amortized cost using the effective
interest rate method.
(8)Carrying value at September 30, 2008 is net of unamortized deferred
financing costs of $36 million (December 31, 2007 - $33 million).
(9) 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 $326 million as at September 30, 2008 (December 31, 2007: carrying
value $122 million; fair value $107 million).
The carrying values of financial instruments included in current assets, current
liabilities, deferred charges and other assets, and deferred credits in the
consolidated balance sheets approximate their fair value, reflecting the
short-term maturity, normal trade credit terms and/or the nature of these
instruments. The fair value of long-term debt is calculated by using quoted
market prices, when available, or by discounting the future cash flow of each
debt instrument at the estimated yield to maturity for the same or similar debt
issues at the balance sheet date. Since the Corporation does not intend to
settle the long-term debt prior to maturity, the fair value estimate does not
represent an actual liability and, therefore, does not include exchange or
settlement costs. The fair value of the Corporation's preference shares is
determined using quoted market prices.
The Corporation and its subsidiaries hedge exposures to fluctuations in interest
rates, foreign exchange rates and natural gas commodity prices through the use
of derivative financial instruments. The Corporation and its subsidiaries do not
hold or issue derivative financial instruments for trading purposes. The
following table summarizes the valuation of the Corporation's consolidated
derivative financial instruments.
As at As at
September 30, 2008 December 31, 2007
Term to Number Carrying Estimated Carrying Estimated
maturity of Value Fair Value Value Fair Value
(Liability) (years) Contracts ($ ($ ($ ($
Asset millions) millions) millions) millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Interest
rate swaps 1 to 2 4 (1) (1) - -
Foreign
exchange
forward
contract 3 1 1 1 - -
Natural gas
derivatives
: (1)
Swaps and
options Up to 3 245 (58) (58) (79) (79)
Gas
purchase
contract less
premiums than 3 108 (3) (3) 5 5
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) The fair values of the natural gas derivatives were recorded in
accounts payable as at September 30, 2008 (December 31, 2007 - in
accounts payable and accounts receivable).
Two of the four 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. The effective portion of changes in the value of the interest rate swaps
at Fortis Properties is recorded in comprehensive income. The remaining
interest rate swaps are held by the Terasen Gas companies. The interest rate
swaps are designated as hedges of cash flow risk related to floating-rate debt
instruments.
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 a liquefied natural gas ("LNG")
storage facility.
The natural gas derivatives 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. At the Terasen Gas companies, changes in the fair
value of the interest rate swaps, 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 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 Corporation 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 relevant market
information about the instruments. 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.
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. Foreign currency exchange rate
fluctuations associated with the translation of the Corporation's US dollar
borrowings designated as hedges of the Corporation's foreign net investments are
recorded in comprehensive income. The Corporation may also periodically enter
into hedges of its foreign currency exposures by entering into forward foreign
currency contracts.
18. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit risk: Risk that a third party to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.
Liquidity risk: Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market risk: Risk that the fair value or future cash flows of a
financial instrument will fluctuate due to changes
in market prices. The Corporation is exposed
to foreign exchange risk, interest rate risk and
commodity price risk.
Credit Risk
For cash and cash equivalents, trade and other accounts receivable, and other
receivables due from customers, the Corporation's credit risk is limited to the
carrying value on the balance sheet. 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. The
Corporation generally has a large and diversified customer base, which minimizes
the concentration of credit risk with the exception of the concentration of
credit risk for FortisAlberta and the Terasen Gas companies as described below.
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 September 30, 2008, its gross exposure to credit risk was
approximately $84 million, representing the projected value of retailer billings
over a 60-day period. The Company has reduced its exposure to approximately $5
million by obtaining from the retailers either a cash deposit, bond, letter of
credit, an investment-grade credit rating from a major rating agency or by
having the retailers obtain a financial guarantee from an entity with an
investment-grade credit rating.
The Terasen Gas companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments, including
natural gas derivatives. The Terasen Gas companies are also exposed to
significant credit risk on physical off-system sales. To mitigate credit risk,
the Terasen Gas companies deal with high credit-quality institutions, in
accordance with established credit-approval practices. The counterparties with
which the Terasen Gas companies have significant transactions are A-rated
entities or better. Due to recent events in the capital markets, including
significant international government intervention in the banking systems, the
Terasen Gas companies have further limited the financial counterparties they
transact with and have reduced the available credit to, or taken additional
security from, the physical off-system sales counterparties with which they
transact. To date, the Terasen Gas companies have not experienced any
counterparty defaults and they do not expect any counterparties to fail to meet
their obligations. The Terasen Gas companies also use netting arrangements to
reduce credit risk and net settles payments with counterparties where net
settlement provisions exist.
The aging analysis of the Corporation's consolidated trade and other accounts
receivable, derivative financial instrument assets and other receivables due
from customers is as follows:
As at As at As at
September June March
($ millions) 30, 2008 30, 2008 31, 2008
---------------------------------------------------------------------
---------------------------------------------------------------------
Not past due 399 647 676
Past due 0-30 days 46 66 95
Past due 31-60 days 9 18 22
Past due 61 days and over 26 26 20
---------------------------------------------------------------------
480 757 813
Less: allowance for doubtful accounts (14) (14) (14)
---------------------------------------------------------------------
466 743 799
---------------------------------------------------------------------
---------------------------------------------------------------------
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.
The recent volatility experienced in the global capital markets may increase the
cost of and timing of issuance of long-term capital by the Corporation and its
subsidiaries.
To mitigate liquidity risk, the Corporation and its larger regulated utilities
have secured multi-year committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements. The
committed credit facility at the Corporation 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 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 annual long-term debt
maturities are expected to be approximately $180 million. The combination of
available credit facilities and low annual debt maturities provides the
Corporation and its subsidiaries with flexibility in the timing of access to the
debt and equity capital markets.
As at September 30, 2008, the Corporation and its subsidiaries had consolidated
authorized lines of credit of $2.2 billion, of which $1.5 billion was unused.
The credit facilities are syndicated almost entirely with the seven largest
Canadian banks with no one bank holding more than 25 per cent of these
facilities. The following summary outlines the credit facilities of the
Corporation and its subsidiaries.
Total as at Total as at
Corporate Regulated Fortis September 30, December 31,
($ millions) and Other Utilities Properties 2008 2007
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Total credit
facilities 715 1,491 13 2,219 2,234
Credit
facilities
utilized:
Short-term
borrowings - (440) - (440) (475)
Long-term debt
(Note 7) (1) (46) (110) - (156) (530)
Letters of
credit
outstanding (1) (89) (1) (91) (159)
--------------------------------------------------------------------------
Credit
facilities
available 668 852 12 1,532 1,070
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) As at September 30, 2008, credit-facility borrowings classified as
long-term debt included $9 million that was included in current
installments of long-term debt and capital lease obligations on the
balance sheet.
At September 30, 2008 and December 31, 2007, 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.
Letters of credit of $50 million previously outstanding at Terasen Inc., related
to its previously owned petroleum transportation business and secured by a
letter of credit from the former parent company, were cancelled during the
second quarter of 2008.
In April 2008, FortisBC renegotiated and amended its $150 million unsecured
committed revolving credit facility, extending the maturity date of the $50
million portion of the facility to May 2011 from May 2010 and extending the $100
million portion to May 2009 from May 2008. The Company has the option to
increase the credit facility to an aggregate of $200 million, subject to bank
approval.
In April 2008, Maritime Electric repaid all outstanding borrowings under its $25
million unsecured credit facility with partial proceeds from a $60 million bond
issue. The credit facility matured in May 2008 and was not renewed. As at
September 30, 3008, Maritime Electric had a $50 million unsecured revolving
credit facility.
In July 2008, TGI renegotiated, on substantially similar terms, its $500 million
unsecured committed revolving credit facility extending the maturity date of the
facility to August 2013 from August 2012.
In August 2008, Newfoundland Power renegotiated, on substantially similar terms,
its $100 million committed revolving credit facility extending the maturity date
to August 2011 from January 2009.
Furthermore, the Corporation and its subsidiaries target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
September 30, 2008, the Corporation's credit ratings were as follows:
Standard & Poor's A- (long-term corporate and unsecured
debt credit rating)
DBRS BBB(high) (unsecured debt credit rating)
The credit ratings reflect the diversity of the operations of Fortis, the
stand-alone nature and financial separation of each of the regulated
subsidiaries of Fortis, management's commitment to maintaining low levels of
debt at the holding company level and the continued focus of Fortis on pursuing
acquisitions of stable regulated utilities.
The following is an analysis of the contractual maturities of the Corporation's
consolidated financial liabilities as at September 30, 2008.
Financial Liabilities
less than greater greater
or equal to than 4-5 than
($ millions) 1 year 1-3 years years 5 years Total
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Short-term borrowings 440 - - - 440
Trade and other accounts
payable 644 - - - 644
Natural gas derivatives 49 12 - - 61
Dividends payable 42 - - - 42
Customer deposits 2 2 1 1 6
Long-term debt, including
current portion (1) 374 299 217 4,268 5,158
Preference shares, classified
as debt - - - 320 320
---------------------------------------------------------------------------
1,551 313 218 4,589 6,671
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Excluding deferred financing costs of $36 million included in
the carrying value as per Note 17.
Market Risk
Foreign Exchange Risk
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. The foreign exchange gain or loss on
the translation of US dollar denominated interest expense partially offsets the
foreign exchange gain or loss on the translation of US dollar denominated
earnings derived from foreign investments.
As at September 30, 2008, all of the Corporation's US$408 million long-term debt
had been designated as a hedge of a portion of the Corporation's foreign net
investments. As at September 30, 2008, the Corporation had approximately US$105
million in foreign net investments remaining to be hedged.
As of January 1, 2008, a 5 per cent appreciation of the US dollar-to-Canadian
dollar exchange rate would have increased earnings by $0.4 million and $0.3
million for the three and nine months ended September 30, 2008, respectively,
and would have decreased comprehensive income by $1 million and $21 million for
the three and nine months ended September 30, 2008, respectively. This
sensitivity analysis is limited to the impact of the translation of US
dollar-denominated expense and revenue streams on earnings and the impact of the
translation of the US dollar borrowings on comprehensive income. The
sensitivity analysis excludes the risk arising from the translation of
self-sustaining foreign operations to the Canadian dollar because this exposure
is limited to the net investment in these operations which is not a financial
instrument.
TGVI's US dollar payments under a contract for the construction of an LNG
storage facility are exposed to fluctuations in the US dollar-to-Canadian dollar
exchange rate. TGVI has entered into a foreign exchange forward contract to
hedge this exposure. As at September 30, 2008, a 5 per cent appreciation of the
US dollar-to-Canadian dollar exchange rate, as it impacts the measurement of the
fair value of the foreign exchange forward contract, in the absence of rate
regulation and with all other variables constant, would have increased
comprehensive income by $0.1 million and $2.6 million for the three and nine
months ended September 30, 2008, respectively. Furthermore, 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. Therefore, any change in fair value would have impacted regulatory assets
or liabilities rather than comprehensive income.
Interest Rate Risk
The Corporation and its operating subsidiaries are exposed to interest rate risk
associated with short-term borrowings and floating-rate debt. The Corporation
and its operating subsidiaries may enter into interest rate swap agreements to
help reduce this risk and, during the first nine months of 2008, the Terasen Gas
companies and Fortis Properties were parties to interest rate swap agreements
that effectively fixed the interest rates on their variable-rate borrowings. As
of January 1, 2008, a 50 basis point increase in interest rates associated with
variable-rate debt, in the absence of rate regulation and with all other
variables remaining constant, would have decreased earnings by $0.4 million and
$1.4 million for the three and nine months ended September 30, 2008,
respectively. Furthermore, certain regulated subsidiaries have regulatory
approval to defer any increase or decrease in interest rate expense resulting
from fluctuations in interest rates associated with variable-rate debt, for
recovery from, or refund to, customers in future rates. Therefore, after
consideration of the operation of regulatory deferral mechanisms, the impact on
earnings associated with the above sensitivity analysis would have been limited
to $0.1 million and $0.4 million for the three and nine months ended September
30, 2008, respectively.
As at September 30, 2008, a 50 basis point increase in interest rates as it
impacts the measurement of fair value of the interest rate swap agreements, in
the absence of rate regulation and with all other variables remaining constant,
would have had a nominal impact on comprehensive income for the three and nine
months ended September 30, 2008. Furthermore, the Terasen Gas companies have
regulatory approval to defer any increase or decrease in the fair value of the
interest rate swap agreements for recovery from, or refund to, customers in
future rates. Therefore, any change in fair value would have impacted
regulatory assets or liabilities rather than comprehensive income.
In addition, certain of the committed credit facilities have fees that are
linked to the Corporation's or subsidiaries' credit ratings. As of January 1,
2008, a downward change in the credit ratings of the Corporation and its
currently rated subsidiaries by one level, with all other variables remaining
constant, would have decreased earnings by $0.2 million and $0.5 million for the
three and nine months ended September 30, 2008, respectively.
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 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. As of January 1, 2008, had the
price of natural gas, with all other variables remaining constant, increased by
$1 per gigajoule, the fair value of the natural gas derivatives would have
increased and, in the absence of rate regulation, comprehensive income would
have increased by $62 million for the nine months ended September 30, 2008.
However, the Terasen Gas companies defer any changes in fair value of the
natural gas derivatives, subject to regulatory approval, for future recovery
from, or refund to, customers in future rates. Therefore, for the nine months
ended September 30, 2008, instead of increasing comprehensive income, the impact
would have increased current regulatory liabilities.
19. CONTINGENT LIABILITIES AND COMMITMENTS
Contingent liabilities
The Corporation and its subsidiaries are subject to various legal proceedings
and claims that arise in the ordinary course of business operations. The
Corporation's contingent liabilities are consistent with disclosures in the
Corporation's 2007 Annual Audited Consolidated Financial Statements, except as
discussed below.
Pursuant to a settlement agreement between FortisAlberta and Her Majesty the
Queen in Right of Alberta (the "Crown"), a Discontinuance of Action was filed on
September 10, 2008 in the Court of Queen's Bench of Alberta in the Judicial
District of Edmonton in relation to a March 24, 2006 statement of claim wherein
the Crown claimed that FortisAlberta was responsible for a fire that occurred in
October 2003 in an area of the Province of Alberta commonly referred to as "Poll
Haven Community Pasture". Payment of the settlement funds was covered by the
terms of an insurance contract between FortisAlberta and its insurer.
Commitments
The nature and amount of the Corporation's commitments are comparable to those
disclosed in the Corporation's Annual Consolidated Financial Statements for the
year ended December 31, 2007, except for those described below for TGVI,
FortisOntario, Maritime Electric, Caribbean Utilities and Fortis Turks and
Caicos.
In April 2008, TGVI, after receiving regulatory approval, entered into a
contract with a third party for the engineering procurement and construction of
an LNG storage facility on Vancouver Island. The contract includes approximately
$55 million to be paid in US dollars. To mitigate the currency fluctuations on
the US dollar portion of the contract, the Company entered into a three-year US
dollar forward-purchase contact (Note 17).
FortisOntario has entered into a new 11.5 -year take-or-pay contract between
Cornwall Electric and Hydro-Quebec Energy Marketing for the supply of
electricity and capacity. The contract, which expires on December 31, 2019,
replaces the previous two-year contract that expired on June 30, 2008. This
take-or-pay contract provides energy up to 100 MW on an as-needed basis and
provides a minimum of 300,000 megawatt hours of energy per contract year
beginning July 1, 2008. As at September 30, 2008, the contract totalled
approximately $297 million through December 31, 2019.
Maritime Electric has two new take-or-pay contracts for the purchase of either
capacity or energy. As at September 30, 2008, the contracts totalled
approximately $90 million through November 30, 2032. The take-or-pay contract
with New Brunswick Power includes, among other things, replacement energy and
capacity for the Point Lepreau Nuclear Generating Station during its 18-month
refurbishment outage.
The other take-or-pay contract is for transmission capacity allowing Maritime
Electric to reserve 30 MW of capacity on the new International Power Line into
the United States.
Caribbean Utilities has entered into an agreement to purchase a 16-MW diesel
generating unit and related equipment from a supplier in Germany for
approximately US$24 million. The unit is expected to be commissioned in summer
2009. Approximately US$5 million has been incurred under the project as at
September 30, 2008.
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, required to be
purchased annually for each of the 12-month periods ended April 30 are: 2009 -
26 and 2010 - 28.
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.
20. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
classifications.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada. With
total assets exceeding $10.5 billion and annual revenues expected to be
approximately $3.7 billion, the Corporation serves more than 2,000,000 gas and
electricity customers. Its regulated holdings include electric distribution
utilities in five Canadian provinces and three Caribbean countries and a natural
gas utility in British Columbia. Fortis owns 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
E: service@computershare.com
W: www.computershare.com/fortisinc
For the quarter ended September 30, 2008, Fortis Inc. will be filing the
Certification of Interim Filings (Form 52-109F2) on SEDAR. Additional
information, including the Fortis 2007 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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