Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved third quarter net
earnings attributable to common equity shareholders of $48 million, or $0.23 per
common share, compared to $45 million, or $0.24 per common share, for the third
quarter of 2012. Year-to-date net earnings attributable to common equity
shareholders were $253 million, or $1.27 per common share, compared to $228
million, or $1.20 per common share, for the same period last year.
Results for the third quarter of 2013 were impacted by the Corporation's
acquisition of CH Energy Group, Inc. ("CH Energy Group") on June 27, 2013 for
US$1.5 billion, including the assumption of US$518 million of debt on closing.
The net purchase price of the acquisition was initially financed using proceeds
from a $601 million common equity offering and drawings under the Corporation's
committed credit facility. Central Hudson Gas & Electric Corporation ("Central
Hudson"), the main business of CH Energy Group, is a regulated transmission and
distribution utility that serves 376,000 electricity and gas customers in New
York State's Mid-Hudson River Valley. Central Hudson contributed $12 million to
earnings for the third quarter of 2013, comparable with performance in the third
quarter of 2012. Due to the common share offering and financing costs associated
with the acquisition, earnings per common share for the third quarter of 2013
were not materially impacted by the acquisition of CH Energy Group.
"Central Hudson has successfully integrated into the Fortis family," says Stan
Marshall, President and Chief Executive Officer, Fortis Inc. "The acquisition is
expected to be accretive to earnings per common share of Fortis beginning in
2015."
Regulated utilities comprise approximately 90% of total assets and serve more
than 2.4 million customers across Canada and in New York State and the
Caribbean. As at September 30, 2013, regulated rate base assets of Fortis exceed
$10 billion.
Canadian Regulated Gas Utilities incurred a loss of $14 million compared to a
loss of $6 million for the third quarter of 2012. The third quarter is normally
a period of lower customer demand due to warmer temperatures. The higher loss
largely related to higher operating and maintenance expenses, decreases in the
allowed rate of return on common shareholders' equity ("ROE") and the equity
component of capital structure as a result of the regulatory decision related to
the first phase of the Generic Cost of Capital ("GCOC") Proceeding in British
Columbia, and lower-than-expected customer additions. The above items were
partially offset by earnings contribution from growth in energy infrastructure
investment.
Canadian Regulated Electric Utilities contributed earnings of $51 million
compared to $55 million for the third quarter of 2012. FortisAlberta's earnings
were approximately $1 million lower quarter over quarter, due to lower net
transmission revenue and $1 million of costs related to flooding in southern
Alberta in June 2013, largely offset by growth in energy infrastructure
investment, customer growth and timing of operating expenses. FortisBC
Electric's earnings decreased $2 million due to a decrease in the interim
allowed ROE as a result of the regulatory decision related to the first phase of
the GCOC Proceeding in British Columbia, lower pole-attachment revenue and
higher effective income taxes. The decreases were partially offset by earnings
contribution from growth in energy infrastructure investment and
lower-than-expected finance charges. At Newfoundland Power, earnings were $1
million lower quarter over quarter, due to the impact of the reversal of
statute-barred Part VI.1 tax in the third quarter of 2012, partially offset by
growth in energy infrastructure investment and lower storm-related costs.
In April 2013 Newfoundland Power received a cost of capital decision maintaining
the utility's allowed ROE at 8.8% and its common equity component of capital
structure at 45% for 2013 through 2015. In May 2013 the British Columbia
Utilities Commission issued its decision, effective January 1, 2013, on the
first phase of its GCOC Proceeding. As a result, the allowed ROE for FortisBC
Energy Inc. has been set at 8.75%, as compared to 9.50% for 2012, and the common
equity component of capital structure has been reduced from 40.0% to 38.5%. The
interim allowed ROEs for FortisBC Energy (Vancouver Island) Inc. ("FEVI"),
FortisBC Energy (Whistler) Inc. ("FEWI") and FortisBC Electric were also reduced
by 75 basis points for 2013 as a result of the first phase of the GCOC
Proceeding, while the common equity components of their capital structures
remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and
FortisBC Electric will be determined in the second phase of the GCOC Proceeding,
which is currently underway. A decision on the proceeding is expected in the
first half of 2014. FortisAlberta's final allowed ROE and capital structure for
2013 remain to be determined.
Caribbean Regulated Electric Utilities contributed $6 million to earnings,
comparable with the third quarter of 2012.
Non-Regulated Fortis Generation contributed $8 million to earnings, up $3
million quarter over quarter. Improved performance mainly related to increased
production in Belize due to higher rainfall.
Non-Utility operations contributed earnings of $6 million compared to $8 million
for the third quarter of 2012. The decrease reflected a loss of approximately
$2.5 million at Griffith Energy Services, Inc., the non-regulated petroleum
supply operations of CH Energy Group, which is comparable with performance in
the third quarter of 2012 and reflects the impact of seasonality. Improved
performance at Fortis Properties' Hospitality Division partially offset the
decrease in earnings.
Corporate and other expenses for the third quarter include $2 million of costs
associated with the redemption of preference shares and a $2 million foreign
exchange loss, compared to a $3 million foreign exchange loss in the third
quarter of 2012. Excluding these impacts, Corporate and other expenses were $17
million for the third quarter, $3 million lower than the third quarter of 2012.
The decrease was primarily due to a higher income tax recovery, resulting from
the release of income tax provisions in the third quarter of 2013 and the
recognition of income tax expense associated with Part VI.1 tax in the third
quarter of 2012. Higher capitalized interest associated with the financing of
construction of the Corporation's 51% controlling ownership interest in the
Waneta Expansion hydroelectric generating facility ("Waneta Expansion") was
offset by higher interest on credit facility borrowings associated with
financing the acquisition of CH Energy Group. The decrease in Corporate and
other expenses was partially offset by higher preference share dividends.
Consolidated capital expenditures were approximately $809 million year-to-date
2013. Construction of the $900 million, 335-megawatt Waneta Expansion in British
Columbia continues on time and on budget, with completion of the facility
expected in spring 2015. Approximately $534 million has been invested in the
Waneta Expansion since construction began in late 2010.
Cash flow from operating activities was $680 million year-to-date 2013 compared
to $804 million for the same period last year, primarily due to unfavourable
changes in working capital.
In July 2013 Fortis issued 10 million 4% Cumulative Redeemable Fixed Rate Reset
First Preference Shares, Series K for gross proceeds of $250 million. The
proceeds were used to redeem all of the Corporation's 5.45% First Preference
Shares, Series C in July 2013 for $125 million, to repay a portion of credit
facility borrowings, and for other general corporate purposes. In October 2013
the Corporation closed a private placement of 10-year US$285 million unsecured
notes at 3.84% and 30-year US$40 million unsecured notes at 5.08%. The proceeds
were used to repay a portion of US dollar-denominated credit facility borrowings
incurred to finance a portion of the CH Energy Group acquisition. In September
2013 FortisAlberta issued 30-year $150 million unsecured debentures at 4.85%,
the proceeds of which are being used to repay credit facility borrowings, to
fund future capital expenditures and for general corporate purposes.
Fortis has consolidated credit facilities of $2.7 billion, of which $1.9 billion
was unused as at September 30, 2013. In August 2013 the Corporation extended the
maturity of its $1 billion committed revolving credit facility to July 2018.
"We remain focused on completing our capital projects for 2013, which are
expected to total approximately $1.2 billion," explains Marshall. "Our five-year
capital program to the end of 2017 is projected to total $6 billion and will
continue to drive growth in earnings and dividends."
FORWARD-LOOKING INFORMATION
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion
and Analysis ("MD&A") has been prepared in accordance with National Instrument
51-102 - Continuous Disclosure Obligations. The MD&A should be read in
conjunction with the interim unaudited consolidated financial statements and
notes thereto for the three and nine months ended September 30, 2013 and the
MD&A and audited consolidated financial statements for the year ended December
31, 2012 included in the Corporation's 2012 Annual Report. Financial information
contained in the MD&A has been prepared in accordance with accounting principles
generally accepted in the United States ("US GAAP") and is presented in Canadian
dollars unless otherwise specified.
Fortis includes forward-looking information in the Management Discussion and
Analysis ("MD&A") within the meaning of applicable securities laws in Canada
("forward-looking information"). The purpose of the forward-looking information
is to provide management's expectations regarding the Corporation's future
growth, results of operations, performance, business prospects and
opportunities, and it may not be appropriate for other purposes. All
forward-looking information is given pursuant to the safe harbour provisions of
applicable Canadian securities legislation. The words "anticipates", "believes",
"budgets", "could", "estimates", "expects", "forecasts", "intends", "may",
"might", "plans", "projects", "schedule", "should", "will", "would" and similar
expressions are often intended to identify forward-looking information, although
not all forward-looking information contains these identifying words. The
forward-looking information reflects management's current beliefs and is based
on information currently available to the Corporation's management. The
forward-looking information in the MD&A includes, but is not limited to,
statements regarding: the Corporation's forecast gross consolidated capital
expenditures for 2013 and total capital spending over the five-year period 2013
through 2017; the expectation that capital investment over the above-noted
five-year period will allow utility rate base and hydroelectric generation
investment to increase at a combined compound annual growth rate of
approximately 6%; the expected nature, timing and capital cost related to the
construction of the Waneta Expansion hydroelectric generating facility ("Waneta
Expansion"); the expectation that, based on current tax legislation, future
earnings will not be materially impacted by Part VI.1 tax; the expectation that
cash required to complete subsidiary capital expenditure programs will be
sourced from a combination of cash from operations, borrowings under credit
facilities, equity injections from Fortis and long-term debt offerings; the
expectation that the combination of available credit facilities and relatively
low annual debt maturities and repayments will provide the Corporation and its
subsidiaries with flexibility in the timing of access to capital markets; the
expected consolidated long-term debt maturities and repayments over the next
five years; the expectation that the Corporation and its subsidiaries will
remain compliant with debt covenants during 2013; the expected timing of filing
of regulatory applications and of receipt of regulatory decisions; the
expectation that the acquisition of CH Energy Group, Inc. will be accretive to
earnings per common share of Fortis beginning in 2015; and the expectation that
the Corporation's capital expenditure program will support continuing growth in
earnings and dividends.
The forecasts and projections that make up the forward-looking information are
based on assumptions which include, but are not limited to: the receipt of
applicable regulatory approvals and requested rate orders, no material adverse
regulatory decisions being received and the expectation of regulatory stability;
FortisAlberta continues to recover its cost of service and earn its allowed rate
of return on common shareholders' equity ("ROE") under performance-based
rate-setting, which commenced for a five-year term effective January 1, 2013; no
significant variability in interest rates; no significant operational
disruptions or environmental liability due to a catastrophic event or
environmental upset caused by severe weather, other acts of nature or other
major events; the continued ability to maintain the gas and electricity systems
to ensure their continued performance; no severe and prolonged downturn in
economic conditions; no significant decline in capital spending; no material
capital project and financing cost overrun related to the construction of the
Waneta Expansion; sufficient liquidity and capital resources; the expectation
that the Corporation will receive appropriate compensation from the Government
of Belize ("GOB") for the fair value of the Corporation's investment in Belize
Electricity that was expropriated by the GOB; the expectation that Belize
Electric Company Limited will not be expropriated by the GOB; the continuation
of regulator-approved mechanisms to flow through the commodity cost of natural
gas and energy supply costs in customer rates; the ability to hedge exposures to
fluctuations in foreign exchange rates, natural gas commodity prices,
electricity prices and fuel prices;
no significant counterparty defaults; the continued competitiveness of natural
gas pricing when compared with electricity and other alternative sources of
energy; the continued availability of natural gas, fuel and electricity supply;
continuation and regulatory approval of power supply and capacity purchase
contracts; the ability to fund defined benefit pension plans, earn the assumed
long-term rates of return on the related assets and recover net pension costs in
customer rates; no significant changes in government energy plans and
environmental laws that may materially negatively affect the operations and cash
flows of the Corporation and its subsidiaries; no material change in public
policies and directions by governments that could materially negatively affect
the Corporation and its subsidiaries; maintenance of adequate insurance
coverage; the ability to obtain and maintain licences and permits; retention of
existing service areas; the ability to report under US GAAP beyond 2014 or the
adoption of International Financial Reporting Standards after 2014 that allows
for the recognition of regulatory assets and liabilities; the continued
tax-deferred treatment of earnings from the Corporation's Caribbean operations;
continued maintenance of information technology infrastructure; continued
favourable relations with First Nations; favourable labour relations; and
sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Risk factors
which could cause results or events to differ from current expectations are
detailed under the heading "Business Risk Management" in this MD&A, the
Corporation's MD&A for the year ended December 31, 2012 and in continuous
disclosure materials filed from time to time with Canadian securities regulatory
authorities. Key risk factors for 2013 include, but are not limited to:
uncertainty of the impact a continuation of a low interest rate environment may
have on the allowed ROE at certain of the Corporation's regulated utilities in
western Canada; risk associated with the amount of compensation to be paid to
Fortis for its investment in Belize Electricity that was expropriated by the
GOB; and the timeliness of the receipt of compensation and the ability of the
GOB to pay the compensation owing to Fortis.
All forward-looking information in the MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, the Corporation
undertakes no obligation to revise or update any forward-looking information as
a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned gas and electric distribution utility in
Canada. Its regulated utilities account for 90% of total assets and serve more
than 2.4 million customers across Canada and in New York State and the
Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada,
Belize and Upstate New York. The Corporation's non-utility investments are
comprised of hotels and commercial real estate in Canada and petroleum supply
operations in the Mid-Atlantic Region of the United States.
Year-to-date September 30, 2013, the Corporation's electricity distribution
systems met a combined peak demand of approximately 6,380 megawatts ("MW") and
its gas distribution system met a peak day demand of 1,238 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, 2013 and to the "Corporate
Overview" section of the 2012 Annual MD&A.
The Corporation's main business, utility operations, is highly regulated and the
earnings of the Corporation's regulated utilities are primarily determined under
cost of service ("COS") regulation. Generally under COS regulation, the
respective regulatory authority sets customer gas and/or electricity rates to
permit a reasonable opportunity for the utility to recover, on a timely basis,
estimated costs of providing service to customers, including a fair rate of
return on a regulatory deemed or targeted capital structure applied to an
approved regulatory asset value ("rate base"). The ability of a regulated
utility to recover prudently incurred costs of providing service and earn the
regulator-approved rate of return on common shareholders' equity ("ROE") and/or
rate of return on rate base assets ("ROA") depends on the utility achieving the
forecasts established in the rate-setting processes. As such, earnings of
regulated utilities are generally impacted by: (i) changes in the
regulator-approved allowed ROE and/or ROA and equity component of capital
structure; (ii) changes in rate base; (iii) changes in energy sales or gas
delivery volumes; (iv) changes in the number and composition of customers; (v)
variances between actual expenses incurred and forecast expenses used to
determine revenue requirements and set customer rates; and (vi) timing
differences within an annual financial reporting period between when actual
expenses are incurred and when they are recovered from customers in rates. When
forward test years are used to establish revenue requirements and set base
customer rates, these rates are not adjusted as a result of actual COS being
different from that which is estimated, other than for certain prescribed costs
that are eligible to be deferred on the balance sheet. In addition, the
Corporation's regulated utilities, where applicable, are permitted by their
respective regulatory authority to flow through to customers, without markup,
the cost of natural gas, fuel and/or purchased power through base customer rates
and/or the use of rate stabilization and other mechanisms.
When performance-based rate-setting ("PBR") mechanisms are utilized in
determining annual revenue requirements and resulting customer rates, a formula
is generally applied that incorporates inflation and assumed productivity
improvements. The use of PBR mechanisms should allow a utility a reasonable
opportunity to recover prudent COS and earn its allowed ROE.
SIGNIFICANT ITEMS
Acquisition of CH Energy Group, Inc.: On June 27, 2013, Fortis acquired all of
the outstanding common shares of CH Energy Group, Inc. ("CH Energy Group") for
US$65.00 per common share in cash, for an aggregate purchase price of
approximately US$1.5 billion, including the assumption of US$518 million of debt
on closing. The net purchase price of approximately $1,019 million (US$972
million) was financed through proceeds from the issuance of 18.5 million common
shares of Fortis pursuant to the conversion of Subscription Receipts on closing
of the acquisition for proceeds of approximately $567 million, net of after-tax
expenses, with the balance being initially funded through drawings under the
Corporation's $1 billion committed credit facility.
CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New
York. Its main business, Central Hudson Gas & Electric Corporation ("Central
Hudson"), is a regulated transmission and distribution ("T&D") utility serving
approximately 300,000 electricity and 76,000 natural gas customers in eight
counties of New York State's Mid-Hudson River Valley. Central Hudson accounts
for approximately 93% of the total assets of CH Energy Group and is subject to
regulation by the New York State Public Service Commission ("PSC") under a
traditional COS model. CH Energy Group's non-regulated operations primarily
consist of Griffith Energy Services, Inc. ("Griffith"), which mainly supplies
petroleum products and related services to approximately 65,000 customers in the
Mid-Atlantic Region of the United States.
To obtain regulatory approval of the acquisition, Fortis committed to provide
Central Hudson's customers and community with approximately US$50 million in
financial benefits. These incremental benefits outlined in the PSC order
approving the acquisition include: (i) US$35 million to cover expenses that
would normally be recovered in customer rates; (ii) guaranteed savings to
customers of more than US$9 million over five years resulting from the
elimination of costs CH Energy Group would otherwise incur as a public company;
and (iii) the establishment of a US$5 million Community Benefit Fund to be used
for low-income customer and economic development programs for communities and
residents of the Mid-Hudson River Valley. In addition, electricity and natural
gas customers of Central Hudson will benefit from a delivery rate freeze through
to June 30, 2015. The Company is committed to invest US$215 million in capital
expenditures over the same two-year period.
The above-noted commitments of US$35 million and US$5 million, together with
acquisition-related expenses of approximately US$8 million, were recognized in
the Corporation's earnings for the second quarter of 2013. The acquisition is
expected to be accretive to earnings per common share of Fortis beginning in
2015.
For further information on Central Hudson, refer to the "Segmented Results of
Operation -Regulated Gas & Electric Utility - United States" section of this
MD&A.
First Preference Shares: In July 2013 Fortis issued 10 million 4% Cumulative
Redeemable Fixed Rate Reset First Preference Shares, Series K for gross proceeds
of $250 million. The proceeds were used to redeem all of the Corporation's 5.45%
First Preference Shares, Series C in July 2013 for $125 million, to repay a
portion of credit facility borrowings, and for other general corporate purposes.
Approximately $2 million of costs associated with the redemption of First
Preference Shares, Series C were expensed in the third quarter.
Long-Term Debt Offering: In September 2013 FortisAlberta issued 30-year $150
million unsecured debentures at 4.85%. The proceeds of the debt offering are
being used to repay credit facility borrowings, to fund future capital
expenditures and for general corporate purposes.
Part VI.1 Tax: In June 2013 the Government of Canada enacted previously
announced legislative changes associated with Part VI.1 tax on the Corporation's
preference share dividends. In accordance with US GAAP, income taxes are
required to be recognized based on enacted tax legislation. In the second
quarter of 2013, the Corporation recognized an approximate $25 million income
tax recovery due to the enactment of higher deductions associated with Part VI.1
tax. The income tax recovery impacted earnings at Newfoundland Power, Maritime
Electric and the Corporation as a result of the allocation of Part VI.1 tax in
previous years. Currently, all legislative changes associated with Part VI.1 tax
are enacted and, as a result, future earnings are not expected to be materially
impacted by Part VI.1 tax.
Receipt of Regulatory Decisions: In March 2013 FortisAlberta received a decision
from its regulator approving an interim increase in customer distribution rates,
effective January 1, 2013, including interim approval of 60% of the revenue
requirement associated with certain capital expenditures in 2013 not otherwise
recovered under performance-based rates. The Company's final allowed ROE and
capital structure for 2013 remain to be determined.
In April 2013 Newfoundland Power received a cost of capital decision maintaining
the utility's allowed ROE at 8.8% and its common equity component of capital
structure at 45% for 2013 through 2015 .
In May 2013 the British Columbia Utilities Commission ("BCUC") issued its
decision, effective January 1, 2013, on the first phase of its Generic Cost of
Capital ("GCOC") Proceeding. As a result, the allowed ROE for FortisBC Energy
Inc. ("FEI") has been set at 8.75%, as compared to 9.50% for 2012, and the
common equity component of capital structure has been reduced from 40.0% to
38.5%. The interim allowed ROEs for FortisBC Energy (Vancouver Island) Inc.
("FEVI"), FortisBC Energy (Whistler) Inc. ("FEWI") and FortisBC Electric were
also reduced by 75 basis points for 2013 as a result of the first phase of the
GCOC Proceeding, while the common equity components of their capital structures
remain unchanged. Final allowed ROEs and capital structures for FEVI, FEWI and
FortisBC Electric will be determined in the second phase of the GCOC Proceeding,
which is currently underway. A decision on the proceeding is expected in the
first half of 2014.
For further discussion on the nature of the above regulatory decisions, refer to
the "Material Regulatory Decisions and Applications" section of this MD&A.
Settlement of Expropriation Matters - Exploits River Hydro Partnership: In March
2013 the Corporation and the Government of Newfoundland and Labrador
("Government") settled all matters, including release from all debt obligations,
pertaining to the Government's December 2008 expropriation of non-regulated
hydroelectric generating assets and water rights in central Newfoundland, then
owned by the Exploits River Hydro Partnership ("Exploits Partnership"), in which
Fortis held an indirect 51% interest. As a result of the settlement, an
extraordinary after-tax gain of approximately $22 million was recognized in the
first quarter of 2013.
Acquisition of the Electrical Utility Assets from the City of Kelowna: FortisBC
Electric acquired the electrical utility assets of the City of Kelowna (the
"City") for approximately $55 million in March 2013, which now allows FortisBC
Electric to directly serve some 15,000 customers formerly served by the City.
FortisBC Electric had provided the City with electricity under a wholesale
tariff and had operated and maintained the City's electrical utility assets
under contract since 2000.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the third quarter and
year-to-date periods ended September 30, 2013 and September 30, 2012 are
provided in the following table.
----------------------------------------------------------------------------
Consolidated Financial Highlights (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions, except for
common share data) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
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Revenue 971 714 257 2,874 2,655 219
Energy Supply Costs 356 235 121 1,143 1,092 51
Operating Expenses 299 203 96 726 621 105
Depreciation and
Amortization 141 118 23 400 351 49
Other Income (Expenses),
Net 2 1 1 (36) (2) (34)
Finance Charges 103 93 10 284 276 8
Income Tax Expense 7 7 - 3 44 (41)
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Earnings Before
Extraordinary Item 67 59 8 282 269 13
Extraordinary Gain, Net of
Tax - - - 22 - 22
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Net Earnings 67 59 8 304 269 35
----------------------------------------------------------------------------
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Net Earnings Attributable
to:
Non-Controlling Interests 3 3 - 7 7 -
Preference Equity
Shareholders 16 11 5 44 34 10
Common Equity
Shareholders 48 45 3 253 228 25
----------------------------------------------------------------------------
Net Earnings 67 59 8 304 269 35
----------------------------------------------------------------------------
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Earnings per Common Share
Before
Extraordinary Item
Basic ($) 0.23 0.24 (0.01) 1.16 1.20 (0.04)
Diluted ($) 0.23 0.24 (0.01) 1.16 1.19 (0.03)
Earnings per Common Share
Basic ($) 0.23 0.24 (0.01) 1.27 1.20 0.07
Diluted ($) 0.23 0.24 (0.01) 1.27 1.19 0.08
Weighted Average Common
Shares
Outstanding (#
millions) 212.0 190.2 21.8 199.1 189.6 9.5
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Cash Flow from Operating
Activities 102 221 (119) 680 804 (124)
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Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- The acquisition of CH Energy Group
-- An increase in gas delivery rates at the FortisBC Energy companies and
the base component of electricity rates at most of the regulated
electric utilities, consistent with rate decisions, reflecting ongoing
investment in energy infrastructure and forecasted certain higher
expenses recoverable from customers
-- Growth in the number of customers, driven by FortisAlberta
-- Increased electricity sales at FortisBC Electric, Newfoundland Power,
Maritime Electric and Fortis Turks and Caicos
-- Favourable foreign exchange associated with the translation of US
dollar-denominated revenue
-- Increased revenue at Fortis Properties
Unfavourable
-- Lower commodity cost of natural gas charged to customers at the FortisBC
Energy companies in the first half of 2013
-- Decreases in the allowed ROEs at the FortisBC Energy companies and
FortisBC Electric, and a decrease in the equity component of capital
structure at FEI, effective January 1, 2013, as a result of the BCUC
decision on the first phase of its GCOC Proceeding
-- Lower average gas consumption by residential and commercial customers,
and lower gas transportation volumes at the FortisBC Energy companies
-- Lower net transmission revenue at FortisAlberta
-- Decreased non-regulated hydroelectric production in Belize in the first
half of 2013, partially offset by increased production in the third
quarter of 2013
Factors Contributing to Quarterly and Year-to-Date
Energy Supply Costs Variances
Unfavourable
-- The acquisition of CH Energy Group
-- Increased electricity sales at FortisBC Electric, Newfoundland Power,
Maritime Electric and Fortis Turks and Caicos, which increased fuel and
power purchases
-- Increased costs at Maritime Electric associated with the return to
service of the New Brunswick Power Point Lepreau nuclear generating
station ("Point Lepreau"), in the fourth quarter of 2012
Favourable
-- Lower commodity cost of natural gas at the FortisBC Energy companies in
the first half of 2013
-- Lower average gas consumption by residential and commercial customers,
and lower gas transportation volumes at the FortisBC Energy companies,
which reduced natural gas purchases
Factors Contributing to Quarterly and Year-to-Date
Operating Expenses Variances
Unfavourable
-- The acquisition of CH Energy Group
-- General inflationary and employee-related cost increases at most of the
Corporation's regulated utilities
-- Higher operating and maintenance expenses at the FortisBC Energy
companies, due to the timing of expenditures during 2012
Factors Contributing to Quarterly and Year-to-Date
Depreciation and Amortization Expense Variances
Unfavourable
-- Continued investment in energy infrastructure at the Corporation's
regulated utilities
-- The acquisition of CH Energy Group
Factors Contributing to Quarterly and Year-to-Date
Other Income (Expenses), Net Variances
Favourable
-- A $2 million foreign exchange loss in the third quarter of 2013 and a $3
million foreign exchange gain year-to-date 2013, compared to a $3
million foreign exchange loss in the third quarter and year-to-date
periods in 2012, associated with the translation of the US dollar-
denominated long-term other asset representing the book value of the
Corporation's expropriated investment in Belize Electricity
Unfavourable
-- Approximately $41 million (US$40 million), or $26 million (US$26
million) after tax, in expenses in the second quarter of 2013 associated
with customer and community benefits offered by the Corporation related
to the acquisition of CH Energy Group
Factors Contributing to Quarterly and Year-to-Date
Finance Charges Variances
Unfavourable
-- The acquisition of CH Energy Group, including interest on the
Corporation's credit facility borrowings associated with financing the
acquisition
-- Higher long-term debt levels in support of the utilities' capital
expenditure programs
Favourable
-- Higher capitalized interest associated with the financing of the
construction of the Corporation's 51% controlling ownership interest in
the Waneta Expansion
Factors Contributing to Quarterly and Year-to-Date
Income Tax Expense Variances
Favourable
-- An approximate $25 million income tax recovery in the second quarter of
2013, due to the enactment of higher deductions associated with Part
VI.1 tax
-- The release of income tax provisions of approximately $2 million and $7
million for the third quarter and year-to-date 2013, respectively
-- Lower earnings before income taxes year-to-date 2013
Unfavourable
-- The acquisition of CH Energy Group
Factor Contributing to Year-to-Date
Extraordinary Gain, Net of Tax Variance
Favourable
-- An approximate $25 million ($22 million after-tax) extraordinary gain
recognized in the first quarter of 2013 on the settlement of
expropriation matters associated with the Exploits Partnership
Factors Contributing to Quarterly Earnings Variance
Favourable
-- The acquisition of CH Energy Group, including earnings contribution of
$12 million from Central Hudson and a net loss of approximately $2.5
million at Griffith
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
-- Lower Corporate and other expenses primarily due to a higher income tax
recovery, resulting from the release of income tax provisions in the
third quarter of 2013 and the recognition of income tax expense
associated with Part VI.1 tax in the third quarter of 2012, and a lower
foreign exchange loss, partially offset by higher preference share
dividends and redemption costs
Unfavourable
-- Decreased earnings at the FortisBC Energy companies, primarily due to:
(i) higher operating and maintenance expenses; (ii) decreases in the
allowed ROE and the equity component of the capital structure as a
result of the regulatory decision related to the first phase of the GCOC
Proceeding; and (iii) lower-than-expected customer additions. The
decreases were partially offset by earnings contribution from growth in
energy infrastructure investment.
-- Decreased earnings at FortisBC Electric mainly due to a decrease in the
interim allowed ROE as a result of the regulatory decision related to
first phase of the GCOC Proceeding, lower pole-attachment revenue and
higher effective income taxes, partially offset by earnings contribution
from growth in energy infrastructure investment and lower-than-expected
finance charges
-- Decreased earnings at FortisAlberta due to lower net transmission
revenue and $1 million of costs related to flooding in southern Alberta
in June 2013, largely offset by growth in energy infrastructure
investment, customer growth and timing of operating expenses
-- Decreased earnings at Newfoundland Power due to the $2.5 million
reversal of statute-barred Part VI.1 tax in the third quarter of 2012,
partially offset by growth in energy infrastructure investment and lower
storm-related costs
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- An approximate $22 million after-tax extraordinary gain recognized in
the first quarter of 2013 on the settlement of expropriation matters
associated with the Exploits Partnership, partially offset by decreased
production in Belize, due to lower rainfall in the first half of 2013
-- Increased earnings at Newfoundland Power and Maritime Electric due to
income tax recoveries associated with Part VI.1 tax of $13 million and
$4 million, respectively, partially offset by the $2.5 million reversal
of statute-barred Part VI.1 tax at Newfoundland Power in the third
quarter of 2012
-- The acquisition of CH Energy Group, as discussed above for the quarter
-- Increased earnings at FortisAlberta, due to continued investment in
energy infrastructure, customer growth and timing of operating expenses,
partially offset by lower net transmission revenue and $1 million of
costs related to flooding in southern Alberta in June 2013
Unfavourable
-- Decreased earnings at the FortisBC Energy companies, for the same
reasons discussed above for the quarter
-- Higher Corporate and other expenses, due to $32 million in CH Energy
Group transaction expenses and higher preference share dividends and
redemption costs. The increases were partially offset by: (i) a higher
income tax recovery due to $6 million associated with Part VI.1 tax and
$7 million associated with the release of income tax provisions; (ii) a
foreign exchange gain associated with the translation of the US dollar-
denominated long-term other asset representing the book value of the
Corporation's expropriated investment in Belize Electricity; and (iii)
lower finance charges.
-- Decreased earnings at FortisBC Electric, for the same reasons discussed
above for the quarter
SEGMENTED RESULTS OF OPERATIONS
The basis of segmentation of the Corporation's reportable segments is consistent
with that disclosed in the 2012 Annual MD&A, except as follows as a result of
the acquisition of CH Energy Group. Central Hudson is reported in a new segment
"Regulated Gas & Electric Utility - United States"; and the former
"Non-Regulated - Fortis Properties" segment is now "Non-Regulated - Non-Utility"
and is comprised of Fortis Properties and Griffith.
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities - Canadian
FortisBC Energy Companies (14) (6) (8) 77 89 (12)
----------------------------------------------------------------------------
Regulated Gas & Electric Utility -
United States
Central Hudson 12 - 12 12 - 12
----------------------------------------------------------------------------
Regulated Electric Utilities -
Canadian
FortisAlberta 25 26 (1) 76 73 3
FortisBC Electric 11 13 (2) 37 38 (1)
Newfoundland Power 8 9 (1) 39 28 11
Other Canadian Electric Utilities 7 7 - 22 19 3
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51 55 (4) 174 158 16
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Regulated Electric Utilities -
Caribbean 6 6 - 15 15 -
Non-Regulated - Fortis Generation 8 5 3 35 15 20
Non-Regulated - Non-Utility 6 8 (2) 15 17 (2)
Corporate and Other (21) (23) 2 (75) (66) (9)
----------------------------------------------------------------------------
Net Earnings Attributable to Common
Equity Shareholders 48 45 3 253 228 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Corporation's regulated utilities, refer to
the "Regulatory Highlights" section of this MD&A. A discussion of the financial
results of the Corporation's reporting segments follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas Volumes (petajoules ("PJ")) 25 26 (1) 132 138 (6)
Revenue ($ millions) 194 192 2 932 1,004 (72)
(Loss) Earnings ($ millions) (14) (6) (8) 77 89 (12)
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(1) Includes FEI, FEVI and FEWI
Factors Contributing to Quarterly and Year-to-Date
Gas Volumes Variances
Unfavourable
-- Lower average gas consumption by residential and commercial customers,
due to warmer temperatures
-- Lower gas transportation volumes, partially due to warmer temperatures
As at September 30, 2013, the total number of customers served by the FortisBC
Energy companies was approximately 947,000. Net customer additions year-to-date
2013 were approximately 2,000.
The FortisBC Energy companies earn approximately the same margin regardless of
whether a customer contracts for the purchase and delivery of natural gas or
only for the delivery of natural gas. As a result of the operation of
regulator-approved deferral mechanisms, changes in consumption levels and the
commodity cost of natural gas from those forecast to set residential and
commercial customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the FortisBC Energy
companies as a major portion of the gas distributed is used for space heating.
Most of the annual earnings of the FortisBC Energy companies are realized in the
first and fourth quarters.
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- An increase in the delivery component of customer rates, effective
January 1, 2013, mainly due to ongoing investment in energy
infrastructure and forecasted higher expenses recoverable from customers
as reflected in the 2012/2013 revenue requirements decision received in
April 2012
-- Higher commodity cost of natural gas charged to customers in the third
quarter of 2013
Unfavourable
-- Lower commodity cost of natural gas charged to customers in the first
half of 2013
-- Decreases in the allowed ROE and the equity component of capital
structure, effective January 1, 2013, as a result of the regulatory
decision in May 2013 related to the first phase of the GCOC Proceeding
in British Columbia
-- Lower average gas consumption by residential and commercial customers,
and lower gas transportation volumes
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- Higher operating and maintenance expenses, due to the timing of
expenditures during 2012
-- Decreases in the allowed ROE and the equity component of the capital
structure, as discussed above. For the third quarter and year-to-date
2013 earnings were reduced by approximately $1 million and $9 million,
respectively, as a result of the above regulatory decision.
-- Lower-than-expected customer additions
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
REGULATED GAS & ELECTRIC UTILITY - UNITED STATES
CENTRAL HUDSON
Central Hudson's electric assets comprised approximately 78% of its total assets
as at September 30, 2013, and include approximately 14,000 kilometres of
distribution lines and 1,000 kilometres of transmission lines. The electric
business met a peak demand of 1,202 MW year-to-date 2013. Central Hudson's
natural gas assets comprise the remaining 22% of its total assets as at
September 30, 2013, and include approximately 1,900 kilometres of distribution
pipelines and more than 264 kilometres of transmission pipelines. The gas
business met a peak day demand of 125 TJ year-to-date 2013, which occurred in
the first quarter of 2013.
Central Hudson primarily relies on electricity purchases from third-party
providers and the New York Independent System Operator ("NYISO")-administered
energy and capacity markets to meet the demands of its full-service electricity
customers. It also generates a small portion of its electricity requirements.
Central Hudson purchases its gas supply requirements at various pipeline receipt
points from a number of suppliers that it has contracted for firm transport
capacity.
Regulation
Central Hudson is regulated by the PSC regarding such matters as rates,
construction, operations, financing and accounting. Certain activities of the
Company are subject to regulation by the U.S. Federal Energy Regulatory
Commission under the Federal Power Act (United States). Central Hudson is also
subject to regulation by the North American Electric Reliability Corporation.
Central Hudson operates under COS regulation as administered by the PSC. The PSC
uses a future test year to establish of rates for the utility and, pursuant to
this method, the determination of the approved rate of return on forecast rate
base and deemed capital structure, together with the forecast of all reasonable
and prudent costs, establishes the revenue requirement upon which the Company's
customer rates are determined. Once rates are approved, they are not adjusted as
a result of actual COS being different from that which was applied for, other
than for certain prescribed costs that are eligible for deferral account
treatment.
Central Hudson's allowed ROE is set at 10% on a deemed capital structure of 48%
common equity. The Company began operating under a three-year rate order issued
by the PSC effective July 1, 2010. As approved by the PSC in June 2013, the
original three-year rate order has been extended for two years, through June 30,
2015, as a condition required to close the acquisition of CH Energy Group by
Fortis. Effective July 1, 2013, Central Hudson is also subject to a modified
earnings sharing mechanism, whereby the Company and customers equally share
earnings in excess of the allowed ROE up to an achieved ROE that is 50 basis
points above the allowed ROE, and share 10%/90% (Company/customers) earnings in
excess of 50 basis points above the allowed ROE.
Central Hudson's approved regulatory regime allows for full recovery of
purchased electricity and natural gas costs. The Company's rates also include
Revenue Decoupling Mechanisms ("RDMs") which are intended to minimize the
earnings impact resulting from reduced energy consumption as energy-efficiency
programs are implemented. The RDMs allow the Company to recognize electricity
delivery revenue and gas revenue at the levels approved in rates for most of
Central Hudson's customer base. Deferral account treatment is approved for
certain other specified costs, including provisions for manufactured gas plant
("MGP") site remediation, pension and other post-employment benefit ("OPEB")
costs.
Financial Highlights
----------------------------------------------------------------------------
Financial Highlights (Unaudited) (1) Quarter
Period Ended September 30 2013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate (2) 1.04
----------------------------------------------------------------------------
Electricity Sales (gigawatt hours ("GWh")) 1,420
Gas Volumes (PJ) 4
Revenue ($ millions) 170
Earnings ($ millions) 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Financial results of Central Hudson are from June 27, 2013, the date of
acquisition. For additional information on the acquisition of CH Energy
Group, including Central Hudson, refer to the "Significant Items -
Acquisition of CH Energy Group, Inc." section of this MD&A.
(2) The reporting currency of Central Hudson is the US dollar.
Electricity Sales and Gas Volumes
Seasonality impacts the delivery revenues of Central Hudson, as electricity
sales are highest during the summer months, primarily due to the use of air
conditioning and other cooling equipment, and gas volumes are highest during the
winter months, primarily due to space heating usage.
Electricity sales for the third quarter were 1,420 GWh compared to 1,454 GWh for
the same period last year. The decrease was mainly due to cooler temperatures in
the third quarter of 2013. Gas volumes for the third quarter were 4 PJ compared
to 6 PJ for the same period last year. The decrease was primarily due to lower
volumes delivered to a power generating facility as a result of reduced facility
operations and lower volumes for resale.
A portion of Central Hudson's electricity sales and gas volumes are to other
entities for resale. Electricity sales for resale do not have an impact on
earnings, as any related earnings or loss is refunded to or collected from
customers, respectively. For gas volumes for resale, 85% of any related earnings
or loss is refunded to or collected from customers, respectively.
Revenue
Revenue for the third quarter was US$164 million compared to US$167 million for
the same period last year. The decrease was primarily due to lower gas volumes
for resale, partially offset by higher revenue from electricity energy
efficiency programs.
Earnings
Earnings for the third quarter were comparable with the same period last year.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (GWh) 3,925 4,099 (174) 12,411 12,434 (23)
Revenue ($ millions) 119 117 2 354 335 19
Earnings ($ millions) 25 26 (1) 76 73 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Energy Deliveries Variances
Unfavourable
-- Lower average consumption by customers in oil and gas industry, due to
decreased activity associated with a low commodity price for natural gas
-- Lower average consumption by residential and commercial customers,
primarily in the third quarter of 2013, as a result of flooding in
southern Alberta in June 2013 and cooler temperatures, which reduced air
conditioning load
-- Lower average consumption by farm and irrigation customers, primarily
due to increased rainfall in the second and third quarters of 2013
Favourable
-- Growth in the number of customers, with the total number of customers
increasing by approximately 9,000 year over year as at September 30,
2013, driven by favourable economic conditions
As a significant portion of FortisAlberta's distribution revenue is derived from
fixed or largely fixed billing determinants, changes in quantities of energy
delivered are not entirely correlated with changes in revenue. Revenue is a
function of numerous variables, many of which are independent of actual energy
deliveries.
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- An interim increase in customer electricity distribution rates,
effective January 1, 2013, associated with the regulator's interim
decision received in March 2013 related to FortisAlberta's PBR
Compliance Application
-- Growth in the number of customers
Unfavourable
-- Lower net transmission revenue, due to favourable volume variances of
approximately $3.5 million and $6.5 million recognized in the third
quarter and year-to-date 2012. As approved by the regulator in April
2012, FortisAlberta assumed the risk of volume variances related to net
transmission costs during 2012. The deferral of transmission volume
variances, however, was reinstated by the regulator effective January 1,
2013. Year-to-date 2013, lower net transmission revenue was partially
offset by approximately $2 million recognized in the first quarter of
2013 associated with the finalization of the 2012 net transmission
volume variances.
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- Lower net transmission revenue of approximately $3.5 million for the
quarter and $4.5 million year to date, as discussed above
-- Restoration costs of approximately $1 million in the third quarter of
2013, related to flooding in southern Alberta in June 2013
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Growth in the number of customers
-- Timing of operating expenses
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 752 728 24 2,324 2,313 11
Revenue ($ millions) 74 71 3 230 225 5
Earnings ($ millions) 11 13 (2) 37 38 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant
and Arrow Lakes hydroelectric generating plants. Excludes the non-
regulated generation operations of FortisBC Inc.'s wholly owned
partnership, Walden Power Partnership. In March 2013 FortisBC Inc.
acquired the City of Kelowna's electrical utility assets for
approximately $55 million. For further information, refer to the
"Significant Items" section of this MD&A.
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Favourable
-- Higher average consumption, due to warmer temperatures in the third
quarter of 2013
Unfavourable
-- Lower average consumption, due to warmer temperatures in the first
quarter of 2013
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- An increase in customer electricity rates, effective January 1, 2013,
mainly due to ongoing investment in energy infrastructure and forecasted
certain higher expenses recoverable from customers as reflected in the
2012/2013 revenue requirements decision received in August 2012
-- Revenue associated with the acquisition of the City of Kelowna's
electrical utility assets in March 2013
-- The 3.3% and 0.5% increase in electricity sales for the quarter and year
to date, respectively
Unfavourable
-- A decrease in the interim allowed ROE, effective January 1, 2013, as a
result of the regulatory decision in May 2013 related to the first phase
of the GCOC Proceeding in British Columbia
-- Differences in the amortization to revenue of flow-through adjustments
owing to customers period over period
-- Lower pole-attachment revenue and a decrease in management fees
resulting from lower third-party activity
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- A decrease in the interim allowed ROE, as discussed above. For the third
quarter and year-to-date 2013 earnings were reduced by approximately $1
million and $3 million, respectively, as a result of the above
regulatory decision.
-- Lower pole-attachment revenue
-- Higher effective income taxes, due to lower deductions for income tax
purposes
Favourable
-- Rate base growth, due to continued investment in energy infrastructure,
including the acquisition of the City of Kelowna's electrical utility
assets in March 2013
-- Lower-than-expected finance charges
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 950 940 10 4,180 4,113 67
Revenue ($ millions) 105 100 5 434 422 12
Earnings ($ millions) 8 9 (1) 39 28 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption in the first half of 2013, reflecting the
higher use of electric-versus-oil heating in new home construction and
economic growth
Unfavourable
-- Lower average consumption by large commercial customers in the third
quarter of 2013
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- The 1.1% and 1.6% increase in electricity sales for the quarter and year
to date, respectively
-- An increase in customer electricity rates, effective July 1, 2013, as
reflected in the 2013/2014 General Rate Application ("GRA") decision
received in April 2013. For further information on this decision refer
to the "Material Regulatory Decisions and Applications" section of this
MD&A.
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher effective income taxes, primarily due to the $2.5 million
reversal of statute-barred Part VI.1 tax in the third quarter of 2012
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Lower storm-related costs due to the impact of Tropical Storm Leslie in
September 2012
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- An approximate $13 million income tax recovery in the second quarter of
2013, due to the enactment of higher deductions associated with Part
VI.1 tax, partially offset by the $2.5 million reversal of statute-
barred Part VI.1 tax in the third quarter of 2012
-- Rate base growth, due to continued investment in energy infrastructure
-- Electricity sales growth
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 580 595 (15) 1,809 1,803 6
Revenue ($ millions) 97 91 6 280 264 16
Earnings ($ millions) 7 7 - 22 19 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Comprised of Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Unfavourable
-- Lower average consumption by customers in Ontario reflecting more
moderate temperatures, energy conservation and continued weak economic
conditions in the region
Favourable
-- Higher average consumption by residential customers on Prince Edward
Island ("PEI"), due to cooler temperatures and an increase in the number
of customers using electricity for home heating
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- Higher electricity sales on PEI combined with an increase in the basic
component of customer rates at Maritime Electric, effective March 1,
2013
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
Unfavourable
-- Lower electricity sales in Ontario
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Favourable
-- An approximate $4 million income tax recovery at Maritime Electric in
the second quarter of 2013, due to the enactment of higher deductions
associated with Part VI.1 tax
-- Electricity sales growth at Maritime Electric
Unfavourable
-- Timing of the recognition of a regulatory rate of return adjustment at
Maritime Electric in 2013 as compared to 2012
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate (2) 1.04 1.00 0.04 1.02 1.00 0.02
----------------------------------------------------------------------------
Electricity Sales (GWh) 197 197 - 560 547 13
Revenue ($ millions) 77 72 5 213 202 11
Earnings ($ millions) 6 6 - 15 15 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Comprised of Caribbean Utilities on Grand Cayman, Cayman Islands, in
which Fortis holds an approximate 60% controlling interest and two
wholly owned utilities in the Turks and Caicos Islands, FortisTCI
Limited ("FortisTCI") and Turks and Caicos Utilities Limited ("TCU"),
acquired in August 2012, (collectively "Fortis Turks and Caicos"). In
June 2013 Atlantic Equipment & Power (Turks and Caicos) Ltd. was
amalgamated with FortisTCI.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar.
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
Favourable
-- Increased electricity sales at Fortis Turks and Caicos due to
approximately 5 GWh and 15 GWh of electricity sales in the third quarter
and year-to-date 2013, respectively, at TCU, which was acquired in
August 2012. Electricity sales at TCU in the third quarter of 2012 were
approximately 2 GWh.
Unfavourable
-- Higher rainfall experienced on Grand Cayman during the third quarter of
2013, which decreased air conditioning load
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- Approximately $3 million for the quarter and $4 million year to date of
favourable foreign exchange associated with the translation of US
dollar-denominated revenue, due to the strengthening of the US dollar
relative to the Canadian dollar period over period
-- The 2.4% increase in electricity sales year to date
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the cost of fuel
-- A 1.8% increase in base customer electricity rates at Caribbean
Utilities, effective June 1, 2013
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Favourable
-- A 1.8% increase in base customer electricity rates at Caribbean
Utilities, effective June 1, 2013
-- Decreased operating expenses at Caribbean Utilities in the first half of
2013, due to lower employee-related costs and maintenance costs
Unfavourable
-- Overall higher depreciation expense, due to continued investment in
energy infrastructure
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Year-to-Date
Periods Ended September 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 104 81 23 242 256 (14)
Revenue ($ millions) 12 8 4 24 26 (2)
Earnings ($ millions) 8 5 3 35 15 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Comprised of the financial results of non-regulated generation assets
in Belize, Ontario, British Columbia and Upstate New York, with a
combined generating capacity of 103 MW, mainly hydroelectric
Factors Contributing to Quarterly and Year-to-Date
Energy Sales Variances
Favourable
-- Increased production in Belize in the third quarter of 2013, due to
higher rainfall
-- Increased production in Ontario and Upstate New York, due to higher
rainfall and a generating unit in Upstate New York being returned to
service for part of the second quarter of 2013, respectively, partially
offset by lower production in British Columbia
Unfavourable
-- Decreased production in Belize in the first half of 2013, due to lower
rainfall
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- Increased production in Belize in the third quarter of 2013
Unfavourable
-- Decreased production in Belize in the first half of 2013
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Favourable
-- Increased production in Belize in the third quarter of 2013
-- An approximate $22 million after-tax extraordinary gain recognized in
the first quarter of 2013 on the settlement of expropriation matters
associated with the Exploits Partnership
Unfavourable
-- Decreased production in Belize in the first half of 2013
NON-REGULATED - NON-UTILITY
The Non-Utility segment is comprised of Fortis Properties and Griffith. Fortis
Properties owns and operates 23 hotels, comprised of more than 4,400 rooms, in
eight Canadian provinces, and owns and operates approximately 2.7 million square
feet of commercial office and retail space, primarily in Atlantic Canada.
Non-regulated operations of CH Energy Group primarily consist of Griffith, which
mainly supplies petroleum products and related services to approximately 65,000
customers in the Mid-Atlantic Region of the United States.
---------------------------------------------------------------------------
Financial Highlights (Unaudited) (1)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 124 65 59 242 181 61
Earnings 6 8 (2) 15 17 (2)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Financial results of Griffith are from June 27, 2013, the date of
acquisition. The reporting currency of Griffith is the US dollar.
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- Revenue of approximately $56 million for the third quarter and year-to-
date 2013 at Griffith
-- Increased revenue at Fortis Properties' Hospitality Division, mainly due
to contribution from the StationPark All Suite Hotel, which was acquired
in October 2012, and an increase in the average daily room rate in all
regions
-- Increased revenue at Fortis Properties' Real Estate Division, mainly due
to the recovery of business occupancy tax from certain tenants in 2013
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- A net loss of approximately $2.5 million in the third quarter of 2013 at
Griffith, which is comparable with the same quarter last year and
reflects the impact of seasonality. A considerable portion of the sales
volume for Griffith is derived directly or indirectly from usage in
space heating and air conditioning and, as a result, seasonality impacts
Griffith's earnings.
Favourable
-- Improved performance at Fortis Properties' Hospitality Division,
partially offset by increased depreciation due to capital additions and
improvements
CORPORATE AND OTHER (1)
---------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenue 6 5 1 19 18 1
Operating Expenses 2 2 - 8 8 -
Depreciation and Amortization - - - 1 1 -
Other Income (Expenses), Net (1) (3) 2 (45) (11) (34)
Finance Charges 13 13 - 34 36 (2)
Income Tax Recovery (5) (1) (4) (38) (6) (32)
---------------------------------------------------------------------------
(5) (12) 7 (31) (32) 1
Preference Share Dividends 16 11 5 44 34 10
---------------------------------------------------------------------------
Net Corporate and Other Expenses (21) (23) 2 (75) (66) (9)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Includes Fortis net Corporate expenses, net expenses of non-regulated
FortisBC Holdings Inc. ("FHI") corporate-related activities, and the
financial results of FHI's wholly owned subsidiary FortisBC Alternative
Energy Services Inc. and FHI's 30% ownership interest in CustomerWorks
Limited Partnership
Factors Contributing to Quarterly
Net Corporate and Other Expenses Variance
Favourable
-- A higher income tax recovery due to: (i) the release of income tax
provisions of approximately $2 million in the third quarter of 2013; and
(ii) approximately $1.5 million in income tax expense in the third
quarter of 2012 associated with Part VI.1 tax. For further information
on Part VI.1 tax, refer to the "Significant Items" section of this MD&A.
-- Decreased other expenses mainly due to a $2 million foreign exchange
loss in the third quarter of 2013, compared to $3 million in the third
quarter of 2012, associated with the translation of the US dollar-
denominated long-term other asset representing the book value of the
Corporation's expropriated investment in Belize Electricity
-- Higher capitalized interest associated with the financing of the
construction of the Corporation's 51% controlling ownership interest in
the Waneta Expansion was offset by higher interest on credit facility
borrowings associated with financing the acquisition of CH Energy Group.
Unfavourable
-- Higher preference share dividends due to: (i) the issuance of First
Preference Shares, Series J in November 2012; (ii) the issuance of First
Preference Shares, Series K in July 2013; and (iii) approximately $2
million of costs associated with the redemption of First Preference
Shares, Series C in July 2013. The increase was partially offset by
lower preference share dividends due to the redemption of First
Preference Shares, Series C in July 2013.
Factors Contributing to Year-to-Date
Net Corporate and Other Expenses Variance
Unfavourable
-- Increased other expenses primarily due to: (i) approximately $41 million
(US$40 million), or $26 million (US$26 million) after tax, in expenses
associated with customer and community benefits offered by the
Corporation to close the acquisition of CH Energy Group in June 2013;
and (ii) approximately $8 million ($6 million after tax) in costs
incurred in the second quarter of 2013 related to the acquisition of CH
Energy Group, compared to approximately $8.5 million ($7.5 million after
tax) year-to-date 2012. For additional information on the acquisition of
CH Energy Group, refer to the "Significant Items" section of this MD&A.
The above-noted increases were partially offset by a foreign exchange
gain of approximately $3 million year-to-date 2013, associated with the
translation of the Corporation's US dollar-denominated long-term other
asset, as discussed above, compared to a foreign exchange loss of
approximately $3 million year-to-date 2012.
-- Higher preference share dividends, as discussed above for the quarter
Favourable
-- A higher income tax recovery due to: (i) an approximate $6 million
income tax recovery year-to-date 2013, due to the enactment of higher
deductions associated with Part VI.1 tax compared to approximately $4.5
million in income tax expense year-to-date 2012 associated with Part
VI.1 tax; and (ii) the release of income tax provisions of approximately
$7 million year-to-date 2013
-- Lower finance charges primarily due to higher capitalized interest
associated with the financing of the construction of the Waneta
Expansion, partially offset by higher interest on credit facility
borrowings associated with financing the acquisition of CH Energy Group
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
year-to-date 2013 are summarized as follows.
NATURE OF REGULATION
----------------------------------------------------------------------------
Supportive
Allowed Returns (%) Features
----------------------------------------
Regulated Regulatory Allowed Future or
Utility Authority Common 2011 2012 2013 Historical Test
Equity(%) Year Used to
Set Customer
Rates
----------------------------------------------------------------------------
ROE COS/ROE
-------------------------
FEI BCUC 38.5 (1) 9.50 9.50 8.75 FEI: Prior to
January 1,
2010, 50%/50%
sharing of
earnings above
or below the
allowed ROE
under a PBR
mechanism that
expired on
December 31,
2009 with a
two-year phase-
out
FEVI BCUC 40 (2) 10.00 10.00 9.25 (2)
FEWI BCUC 40 (2) 10.00 10.00 9.25 (2) ROEs
established by
the BCUC -
2013 ROEs are
under review
---------------
Future Test
Year
----------------------------------------------------------------------------
FortisBC BCUC 40 (2) 9.90 9.90 9.15 (2) COS/ROE
Electric
PBR mechanism
for 2009
through 2011:
50%/50% sharing
of earnings
above or below
the allowed ROE
up to an
achieved ROE
that is 200
basis points
above or below
the allowed ROE
- excess to
deferral
account
ROE established
by the BCUC -
2013 ROE is
under review
---------------
Future Test
Year
----------------------------------------------------------------------------
Central PSC 48 (3) 10.00 10.00 10.00 COS/ROE
Hudson (3)
Earnings
sharing
mechanism
effective July
1, 2013:
50%/50% sharing
of earnings
above the
allowed ROE up
to 50 basis
points above
the allowed
ROE; and
10%/90% sharing
of earnings in
excess of 50
basis points
above the
allowed ROE
ROE established
by PSC
---------------
Future Test
Year
----------------------------------------------------------------------------
FortisAlberta Alberta 41 (4) 8.75 8.75 8.75 (4) COS/ROE
Utilities
Commission
("AUC")
PBR mechanism
for 2013
through 2017
with capital
tracker account
and other
supportive
features
ROE established
by the AUC -
2013 ROE is
under review
---------------
2012 test year
with 2013
through 2017
rates set using
PBR mechanism
----------------------------------------------------------------------------
Newfoundland Newfoundland 45 8.38 8.80 8.80 COS/ROE
Power and Labrador +/- +/- +/-
Board of 50 bps 50 bps 50 bps
ommissioners
of Public
Utilities
("PUB")
The allowed ROE
was set using
an automatic
adjustment
formula tied to
long-term
Canada bond
yields for
2011. ROE
established by
the PUB for
2012 through
2015
---------------
Future Test
Year
----------------------------------------------------------------------------
Maritime Island 40 9.75 9.75 9.75 COS/ROE
Electric Regulatory
and Appeals
Commission
---------------
Future Test
Year
----------------------------------------------------------------------------
FortisOntario Ontario Canadian
Energy Niagara Power -
Board COS/ROE
("OEB")
Canadian 40 8.01 8.01 8.93 (5) Algoma Power -
Niagara COS/ROE and
Power subject to
Rural and
Remote Rate
Algoma Power 40 9.85 9.85 9.85 (5) Protection
("RRRP")
program
Franchise Cornwall
Agreement Electric -
Cornwall Price cap with
Electric commodity cost
flow through
---------------
Canadian
Niagara Power -
2009 test year
for 2011 and
2012; 2013 test
year for 2013
Algoma Power -
2011 test year
for 2011, 2012
and 2013
----------------------------------------------------------------------------
ROA COS/ROA
-------------------------
Caribbean Electricity N/A 7.75 - 7.25 - 6.50 -
Utilities Regulatory 9.75 9.25 8.50
Authority
("ERA")
Rate-cap
adjustment
mechanism based
on published
consumer price
indices
The Company may
apply for a
special
additional rate
to customers in
the event of a
disaster,
including a
hurricane.
---------------
Historical Test
Year
----------------------------------------------------------------------------
Fortis Turks Utilities N/A 17.50 17.50 17.50 COS/ROA
and Caicos make annual (6) (6) (6)
filings to
the
Government
of the Turks
and Caicos
Islands
If the actual
ROA is lower
than the
allowed ROA,
due to
additional
costs resulting
from a
hurricane or
other event,
the utilities
may apply for
an increase in
customer rates
in the
following year.
---------------
Future Test
Year
----------------------------------------------------------------------------
(1) Effective January 1, 2013. For 2011 and 2012, the allowed deemed
equity component of the capital structure was 40%.
(2) Capital structures and allowed ROEs for 2013 are interim and are
subject to change based on the outcome of the second phase of the GCOC
Proceeding. The allowed ROEs for 2013 reflect the benchmark 8.75%
allowed ROE for FEI, as set by the BCUC, and risk premiums associated
with each of these utilities.
(3) Effective until June 30, 2015
(4) Capital structure and allowed ROE for 2013 are interim and are subject
to change based on the outcome of a cost of capital proceeding.
(5) Based on the ROE automatic adjustment formula, the allowed ROE for
regulated electric utilities in Ontario is 8.93% for 2013. This ROE is
not applicable to the regulated electric utilities until they are
scheduled to file full COS rate applications. As a result, the allowed
ROE of 8.93% is not applicable to Algoma Power for 2013.
(6) Amount provided under licences as it relates to FortisTCI. Amount
provided under licence for TCU is 15%. Achieved ROAs at the utilities
were significantly lower than those allowed under licences as a result
of the inability, due to economic and political factors, to increase
base electricity rates associated with significant capital investment
in recent years.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
----------------------------------------------------------------------------
Regulated Utility Summary Description
----------------------------------------------------------------------------
FEI/FEVI/FEWI - Effective January 1, 2013, rates increased by
approximately 1.6% for typical residential customers at
FEI in the Lower Mainland, as a result of an increase
in delivery rates in accordance with the BCUC's
decision in April 2012 pertaining to the FortisBC
Energy companies' 2012/2013 Revenue Requirements
Application ("RRA"). Natural gas commodity rates
effective January 1, 2013 remained unchanged for
customers at FEI.
- Effective July 1, 2013, due to an increase in natural
gas commodity costs, rates for residential customers at
FEI in the Lower Mainland increased by approximately
6.8%.
- In February 2012 the BCUC approved FEI's amended
application for a general tariff for the provision of
compressed natural gas and liquefied natural gas
("LNG") refuelling services for transportation
vehicles. FEI has received either permanent or interim
rate approval for four refuelling projects. In June
2013 FEI received a decision on changing its LNG sales
and dispensing service rate schedule from a pilot
program to a permanent program. The decision did not
approve the program as permanent, but extended the
pilot program until the end of 2020, and set out the
rate to be charged. In addition, FEI and FEVI received
BCUC approval for rate treatment of expenditures under
the Greenhouse Gas Reductions (Clean Energy) Regulation
("GGRR") under the Clean Energy Act that was announced
in May 2012. In May 2013 FEI filed an application for
approval of its first refuelling station under the GGRR
and in July 2013 the Company received approval of the
rates to be charged to customers. In September 2013
FEVI filed an application for approval of its first
refuelling station under the GGRR and a decision is
expected in the fourth quarter of 2013.
- In August 2011 FEI received a BCUC decision on the
use of Energy Efficiency and Conservation ("EEC") funds
as incentives for natural gas-fuelled vehicles
("NGVs"). FEI had made these funds available to assist
large customers in purchasing NGVs in lieu of vehicles
fuelled by diesel. The decision determined that it was
not appropriate to use EEC funds for the above-noted
purpose and the BCUC requested that FEI provide further
submissions to determine the prudency of the EEC
incentives. In August 2012 an application was filed
with the BCUC to review the prudency of the EEC
incentives totalling approximately $6 million. A
decision was received in April 2013 in which the BCUC
determined that the EEC incentives for NGVs were
prudently incurred and can be recovered from customers
in rates.
- During the first quarter of 2013, the BCUC approved
the capital expenditures for the Telus Garden project
at FortisBC Alternative Energy Services Inc. ("FAES");
however, approval of revisions to the rate design and
rates is pending. In July 2013 the BCUC approved the
capital expenditures for the Kelowna District Energy
System project; however, approval of revisions to the
rate design and rates is also pending. In May 2013 the
BCUC initiated a process to review a proposal for a
streamlined regulatory framework for thermal energy
system utilities in British Columbia. The process is
ongoing with a decision expected in the fourth quarter
of 2013 or early 2014. In September 2013 FAES received
interim rate approval for four smaller legacy projects.
In October 2013 FAES applied for approval of a project
under the proposed regulatory framework and a
regulatory review process for this project has not yet
been determined.
- In April 2012 the FortisBC Energy companies applied
to the BCUC for the necessary approvals to amalgamate
the three utilities and implement common rates across
the service territories served by the amalgamated
entity, effective January 1, 2014. The BCUC issued its
decision in February 2013 denying the request to
implement common rates. The FortisBC Energy companies
filed a leave to appeal the decision to the British
Columbia Court of Appeal in March 2013 and filed an
Application for Reconsideration with the BCUC in April
2013. In June 2013 the BCUC determined that the
reconsideration application will be heard. The
regulatory process to review the reconsideration
application will be completed in November 2013 and a
decision is expected in early 2014.
- The public oral hearing for the first phase of a GCOC
Proceeding to determine the allowed ROE and appropriate
capital structure for FEI, the designated low-risk
benchmark utility in British Columbia, occurred in
December 2012. In May 2013 the BCUC issued its decision
on the first phase of the GCOC Proceeding. Effective
January 1, 2013, the decision set the ROE of the
benchmark utility at 8.75%, compared to 9.50% for 2012,
with a 38.5% equity component of capital structure,
compared to 40% for 2012. The equity component of
capital structure will remain in effect until December
31, 2015. Effective January 1, 2014 through December
31, 2015, the BCUC is also introducing an Automatic
Adjustment Mechanism ("AAM") to set the ROE for the
benchmark utility on an annual basis. The AAM will take
effect when the long-term Government of Canada bond
yield exceeds 3.8%. FEVI, FEWI and FortisBC Electric
will have their allowed ROEs and capital structures
determined in the second phase of the GCOC Proceeding.
As a result of the BCUC's decision on the first phase
of the GCOC Proceeding, which reduced the allowed ROE
of the benchmark utility by 75 basis points, the
interim allowed ROEs for FEVI, FEWI and FortisBC
Electric decreased to 9.25%, 9.25% and 9.15%,
respectively, effective January 1, 2013, while the
deemed equity component of capital structures remained
unchanged. The allowed ROEs and equity component of
capital structures for FEVI, FEWI and FortisBC Electric
could change further as a result of the outcome of the
second phase of the GCOC Proceeding. In March 2013 the
BCUC initiated the second phase of the GCOC Proceeding.
The review process for the second phase is underway and
a decision is expected in the first half of 2014.
- In June 2013 FEI filed an application with the BCUC
for a Multi-Year Performance-Based Ratemaking Plan for
2014 through 2018. Pursuant to an Evidentiary Update
filed in September 2013, the application assumes a 2014
forecast midyear rate base for FEI of approximately
$2,789 million. The application also requests approval
of a delivery rate increase for 2014 of approximately
1.4%, determined under a formula approach for operating
and capital costs, and a continuation of this rate-
setting methodology for a further four years. The
regulatory process to review the application will
continue throughout 2013 and 2014, with a decision
expected mid-2014.
- In September 2013 FEVI filed an application for
Revenue Requirements and Rates for 2014, proposing to
hold 2014 rates at existing levels. In October 2013
FEWI also filed an application for Revenue Requirements
and Rates for 2014, proposing to hold 2014 rates at
existing levels. Decisions on the applications are
expected in early 2014.
----------------------------------------------------------------------------
FortisBC Electric - Effective January 1, 2013, as approved by the BCUC in
its August 2012 decision pertaining to FortisBC
Electric's 2012/2013 RRA, customer electricity rates
increased 4.2%.
- In July 2012 FortisBC Electric filed its Advanced
Metering Infrastructure ("AMI") Application, which was
updated in early 2013. A regulatory review by the BCUC
and various interveners concluded with an oral hearing
in March 2013. In July 2013 the BCUC approved the AMI
project for a total cost of approximately $51 million.
The AMI project proposes to improve and modernize
FortisBC Electric's grid by exchanging its manually
read meters with advanced meters. In August 2013 the
Company filed a Radio-Off Meter Option Application,
which proposes that the incremental cost of opting-out
of AMI be borne by customers who choose to opt-out. The
BCUC is reviewing the application and a decision is
expected in the first quarter of 2014.
- In March 2013 the BCUC approved the acquisition by
FortisBC Electric of the City of Kelowna's electrical
utility assets and allowed for approximately $38
million of the $55 million purchase price to be
included in FortisBC Electric's rate base, resulting in
the recognition of approximately $14 million of
goodwill and a $3 million deferred income tax asset.
The transaction closed in March 2013, which allows
FortisBC Electric to directly serve approximately
15,000 customers formerly served by the City. Prior to
the acquisition, FortisBC Electric had provided the
City with electricity under a wholesale tariff and had
operated and maintained the City's electrical utility
assets under contract since 2000.
- In March 2012 the BCUC ordered a written hearing
process to review the prudency of approximately $29
million in capital expenditures already incurred
related to the Kettle Valley Distribution Source
Project, which was substantially completed in 2009. In
April 2013 the BCUC issued a decision approving
substantially all of the $29 million to be included in
rate base, effective from January 1, 2012.
- In July 2013 FortisBC Electric filed an application
with the BCUC for a Multi-Year Performance-Based
Ratemaking Plan for 2014 through 2018. Pursuant to an
Evidentiary Update filed in October 2013, the
application assumes a 2014 forecast midyear rate base
of approximately $1,192 million. The application also
requests approval of a basic customer rate increase for
2014 of approximately 3.3%, determined under a formula
approach for operating and capital costs, and a
continuation of this rate-setting methodology for a
further four years. The regulatory process to review
the application will continue throughout 2013 and 2014,
with a decision expected mid-2014.
----------------------------------------------------------------------------
Central Hudson - There were no material regulatory decisions and
applications at Central Hudson in the third quarter of
2013. For further information on regulation at Central
Hudson, refer to the "Regulated Gas & Electric Utility
- United States" section of this MD&A.
----------------------------------------------------------------------------
FortisAlberta - In September 2012 the AUC issued a generic PBR
Decision outlining the PBR framework applicable to
distribution utilities in Alberta, including
FortisAlberta, for a five-year term, which commenced
January 1, 2013. In the PBR Decision, a formula that
estimates inflation annually and assumes productivity
improvements is to be used by the distribution
utilities to determine customer rates on an annual
basis. The PBR framework also includes mechanisms for
the recovery or settlement of items determined to flow
through directly to customers and the recovery of costs
related to capital expenditures that are not being
recovered through the inflationary factor of the
formula. The AUC also approved: (i) a Z factor
permitting an application for recovery of costs related
to significant unforeseen events; (ii) a PBR re-opener
mechanism permitting an application to re-open and
review the PBR plan to address specific problems with
the design or operation of the PBR plan; and (iii) an
ROE efficiency carry-over mechanism permitting an
efficiency incentive by allowing the utility to
continue to benefit from any efficiency gains achieved
during the PBR term for two years following the end of
the term. The PBR formula does, however, raise some
concern and uncertainty for FortisAlberta regarding the
treatment of certain capital expenditures. While the
PBR Decision did provide for a capital tracker
mechanism for the recovery of costs related to certain
capital expenditures, FortisAlberta sought further
clarification regarding this mechanism in a Review and
Variance ("R&V") Application and a Capital Tracker
Application and sought leave to appeal the issue with
the Alberta Court of Appeal.
- In March 2013 the AUC issued a decision denying the
R&V Application. FortisAlberta has filed a leave to
appeal the decision on similar grounds as the leave to
appeal the PBR Decision. Both appeals have been
adjourned pending further determinations in outstanding
PBR-related proceedings.
- In January 2013 FortisAlberta filed a Phase II
Distribution Tariff Application ("Phase II DTA"), which
proposed rates by customer class based on a cost
allocation study and requested that the 2012 interim
distribution rates by customer class be made final for
2012 and 2013, subject to further adjustments as a
result of the PBR decision, and be applied to rates
effective January 1, 2014. The Phase II DTA proceeding
is complete and a decision is expected in the fourth
quarter of 2013. The outcome of the proceeding is not
expected to have a material impact on FortisAlberta's
2013 financial results.
- In March 2013 the AUC issued an interim decision
regarding the Compliance Applications filed by the
distribution utilities in Alberta. The interim decision
approved a combined inflation and productivity factor
of 1.71%, certain adjustments to the Company's going-in
rates, including Y factor amounts and a K factor
placeholder equal to 60% of the applied for capital
tracker amount. For FortisAlberta, the AUC approved
approximately $14.5 million of the $24 million in
revenue requested in the utility's 2013 Capital Tracker
Application. The decision resulted in an interim
increase in FortisAlberta's distribution rates of
approximately 4%, effective January 1, 2013, with
collection from customers commencing April 1, 2013. A
final decision on the Compliance Application was
received in July 2013 directing the Company to continue
to use interim rates until all remaining 2013
placeholders have been determined. A hearing on the
Capital Tracker Application was held in June and July
2013. A decision is expected in the fourth quarter of
2013 and could result in further adjustments to
FortisAlberta's 2013 distribution rates. When a
decision is received, the impact of any adjustment to
the K factor placeholder will be reflected in revenue.
- In September 2013 FortisAlberta filed its 2014 Annual
Rates Filing. The rates and riders, proposed to be
effective on an interim basis for January 1, 2014,
include a 5.36% increase to the distribution component
of customer rates. This increase reflects a combined
inflation and productivity factor of 1.59%, a K factor
based on the capital tracker placeholder of 60% applied
to the capital expenditure forecast for 2014, and a net
refund of Y factor balances. A decision on this filing
is expected in the fourth quarter of 2013.
- In October 2012 the AUC initiated a 2013 GCOC
Proceeding to establish the final allowed ROE for 2013
and determine whether a formulaic ROE automatic
adjustment mechanism should be re-established. In
November 2012 the 2013 GCOC Proceeding was suspended
until other regulatory matters were resolved. In April
2013 the AUC recommenced the 2013 GCOC Proceeding to
set the allowed ROE and capital structure for
distribution utilities in Alberta for 2013, as well as
the allowed ROE for 2014. In addition, an interim
allowed ROE for 2015 will be established. In this
proceeding the AUC may consider the possibility of re-
establishing a formula-based approach to setting annual
ROE. The process for the 2013 GCOC Proceeding commenced
in the second quarter of 2013 and a hearing is
scheduled for early 2014. The expected outcome of this
proceeding is currently unknown.
- In the PBR Decision, the AUC determined that annual
Capital Tracker Applications will be filed in March for
projects planned for the subsequent year. Accordingly,
FortisAlberta would normally have applied for its 2014
Capital Tracker in March 2013. However, given that a
decision on the 2013 Capital Tracker Application is
outstanding, the AUC determined that the filing of the
2014 Capital Tracker Application would be delayed until
after a decision on the 2013 application is issued.
With a decision on the 2013 Capital Tracker Application
expected in the fourth quarter of 2013, it is expected
that both the 2014 and 2015 Capital Tracker
Applications will be filed in the first quarter of
2014.
- In its 2011 GCOC Decision, the AUC made statements
regarding cost responsibility for stranded assets,
which FortisAlberta and other utilities challenged as
being incorrectly made. The AUC's statements implied
that the shareholder is responsible for the cost of
stranded assets in a broader sense than that generally
understood by regulated utilities and, to an extent,
also conflicts directly with the Electric Utilities Act
(Alberta). As a result, FortisAlberta, together with
other Alberta utilities, filed an R&V Application with
the AUC. In June 2012 the AUC decided it would not
permit an R&V of the decision in question but would
examine the issue in the Utility Asset Disposition
("UAD") Proceeding, which was reinitiated in November
2012. FortisAlberta and the other Alberta utilities had
also sought leave to appeal the stranded asset
pronouncements with the Alberta Court of Appeal and
temporarily adjourned that court process pending the
AUC's follow-up proceeding. Any decision by the AUC
regarding the treatment of stranded assets cannot alter
a utility's right to a reasonable opportunity to
recover prudent COS and earn a fair ROE. The UAD
proceeding also seeks to clarify the regulatory
treatment of the disposition of assets that were
formally used in the provision of regulated services.
The UAD proceeding has closed and a decision is
expected in the fourth quarter of 2013. The outcome of
this proceeding is currently unknown.
----------------------------------------------------------------------------
Newfoundland - In April 2013 the PUB issued its decision related to
Power Newfoundland Power's 2013/2014 GRA, which was filed in
September 2012, to establish the Company's cost of
capital for rate-making purposes. In its decision, the
PUB ordered that the allowed ROE and common equity
component of capital structure remain at 8.8% and 45%,
respectively, for 2013 through 2015. The PUB also
ordered: (i) the recognition of pension expense for
regulatory purposes in accordance with US GAAP and the
related regulatory asset to be recovered from customers
over 15 years; (ii) a decrease in the overall composite
depreciation rate to 3.42% from 3.47%; (iii) the
deferral of annual customer energy conservation program
costs to be recovered from customers over the
subsequent seven-year period; and (iv) the approval of
various regulatory amortizations over a three-year
period, including cost-recovery deferrals recognized in
2011 and 2012, costs associated with the GRA and the
December 31, 2011 balance in the Weather Normalization
Account. The impact of the decision resulted in an
overall average increase in customer electricity rates
of approximately 4.8% effective July 1, 2013 and the
deferral of approximately $4 million of costs incurred
in 2013 but not recovered from customers, due to the
timing of collection in customer rates. The cumulative
impact of the decision was recorded in the second
quarter of 2013, when the decision was received.
Newfoundland Power is required to file its GRA for 2016
on or before June 1, 2015.
- Effective July 1, 2013, the PUB approved an overall
average decrease in Newfoundland Power's customer
electricity rates of approximately 3.1% to reflect the
combined impact of the annual operation of Newfoundland
Power's Rate Stabilization Account ("RSA") and the
above-noted GRA decision. Through the annual operation
of Newfoundland Hydro's Rate Stabilization Plan,
variances in the cost of fuel used to generate
electricity that Newfoundland Hydro sells to
Newfoundland Power are captured and flowed through to
customers through the operation of the Company's RSA.
As a result of a decrease in the forecast cost of oil
to be used to generate electricity at Newfoundland
Hydro, customer electricity rates decreased
approximately 7.9% effective July 1, 2013. The RSA also
captures variances in certain of Newfoundland Power's
costs, such as pension and energy supply costs. The
decrease in customer rates as a result of the operation
of the RSA is not expected to impact Newfoundland
Power's earnings in 2013.
- In September 2013 the PUB approved Newfoundland
Power's 2014 Capital Expenditure Plan totalling
approximately $85 million, before customer
contributions.
----------------------------------------------------------------------------
Maritime Electric - In December 2012 the Electric Power (Energy Accord
Continuation) Amendment Act ("Accord Continuation Act")
was enacted, which sets out the inputs, rates and other
terms for the continuation of the PEI Energy Accord for
an additional three years covering the period March 1,
2013 through February 29, 2016. Under the terms of the
Accord Continuation Act, Maritime Electric received, in
March 2013, proceeds of approximately $47 million from
the Government of PEI upon its assumption of Maritime
Electric's $47 million regulatory asset related to
certain deferred incremental replacement energy costs
during the refurbishment of Point Lepreau. Over the
above-noted three-year period, increases in electricity
costs for a typical residential customer have been set
at 2.2%, effective March 1 annually, and Maritime
Electric's allowed ROE has been capped at 9.75% each
year. The resulting customer rate increases are
primarily due to higher COS and the collection from
customers by Maritime Electric, acting as an agent on
behalf of the Government of PEI, of Point Lepreau-
related costs assumed by the Government of PEI. The
proceeds were used by Maritime Electric to repay short-
term borrowings, to pay a special dividend to Fortis to
maintain the utility's capital structure and to finance
its capital expenditure program.
- In July 2013 Maritime Electric filed its 2014 Capital
Budget Application totalling approximately $28 million,
before customer contributions.
----------------------------------------------------------------------------
FortisOntario - Effective January 1, 2013, residential customer rates
in Fort Erie, Gananoque and Port Colborne increased by
an average of 6.8%, 5.9% and 7.4%, respectively. The
rate increases were the result of the OEB's decision
pertaining to FortisOntario's 2013 COS Application
using a 2013 forward test year and the recovery of
smart meter costs and stranded assets related to
conventional meters and reflect an allowed ROE of
8.93%.
- In March 2013 the OEB issued its decision on Algoma
Power's Third-Generation Incentive-Regulation Mechanism
("IRM") Application for customer electricity
distribution rates and smart meter cost recovery,
effective January 1, 2013, resulting in an overall
increase in residential and commercial customer
distribution rates of 3.75%. Residential and commercial
customer distribution rates are adjusted by the average
increase in customer rates of all other distributor
rate changes in Ontario in the most recent rate year.
The difference in the recovery of COS in residential
and commercial customer distribution rates and the
revenue requirement is compensated from RRRP program
funding. Recovery of smart meter costs allocated to
residential customers will also be recovered from RRRP
program funding as ordered by the OEB. Total RRRP
program funding for 2013 is expected to be
approximately $12 million.
- In August 2013 Canadian Niagara Power and Algoma
Power filed applications with the OEB requesting
approval for customer electricity distribution rates,
effective January 1, 2014, based on the Fourth-
Generation IRM. Under the Fourth-Generation IRM, which
is effective for utilities in Ontario on or after
January 1, 2014, in non-rebasing years customer
electricity distribution rates are set using
inflationary factors less a productivity factor.
----------------------------------------------------------------------------
Caribbean Utilities - In June 2013 the ERA approved Caribbean Utilities'
2013-2017 Capital Investment Plan for US$123 million
related to non-generation installation capital
expenditures. Capital expenditures relating to
additional generation installation are subject to ERA
approval through a competitive bid process.
- A Certificate of Need was filed with the ERA by
Caribbean Utilities in November 2011, due to the
upcoming retirements of some of the Company's
generating units due to begin in mid-2014. In March
2012 proposals for the installation of new generation
units from six qualified bidders, including Caribbean
Utilities, was requested by the ERA and the Company's
proposal was submitted in July 2012. In February 2013
the ERA awarded the bid to develop, install and operate
two new 18-MW generation units to a third party. In
April 2013 the ERA announced that it would be engaging
an independent party to conduct an investigation of
irregularities in the bid process. In July 2013 the ERA
announced that it has cancelled the solicitation
process as a result of unavoidable and unforeseen
delays. The need for additional firm generating
capacity for mid-2014 remains. In light of the ERA's
decision to cancel the solicitation process, Caribbean
Utilities will explore all cost-effective options with
the ERA to ensure that there is sufficient installed
generating capacity to serve the needs of its customers
until the firm capacity needs can be met.
- Effective June 1, 2013, following review and approval
by the ERA, Caribbean Utilities' base customer
electricity rates increased by 1.8% as a result of
changes in the applicable consumer price indices and
the utility's applicable targeted allowed ROA for the
2013 rate adjustment.
----------------------------------------------------------------------------
Fortis Turks and - In March 2013 the Fortis Turks and Caicos utilities
Caicos submitted their 2012 annual regulatory filings
outlining performance in 2012. Included in the filings
were the calculations, in accordance with the
utilities' licences, of rate base of US$195 million for
2012 and cumulative shortfall in achieving allowable
profits of US$105 million as at December 31, 2012.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheet between September 30, 2013 and December 31, 2012.
Significant Changes in the Consolidated Balance Sheet (Unaudited) between
September 30, 2013 and December 31, 2012
----------------------------------------------------------------------------
Balance Sheet Increase Other Explanation for Other
Account Due to Increase/ Increase/(Decrease)
CH Energy Group (Decrease)
($ millions) ($ millions)
----------------------------------------------------------------------------
Accounts 110 (174) The decrease was primarily
receivable due to the impact of a
seasonal decrease in sales
at the FortisBC Energy
companies and Newfoundland
Power.
----------------------------------------------------------------------------
Regulatory 253 18 The increase was mainly due
assets - to higher regulatory
current and deferred income taxes and
long-term the deferral of various
other costs, as permitted by
the regulators, mainly at
the FortisBC Energy
companies and FortisAlberta.
The above increases were
partially offset by proceeds
of approximately $47 million
received from the Government
of PEI in March 2013 upon
its assumption of Maritime
Electric's replacement
energy deferral associated
with Point Lepreau, and the
change in the deferral of
the fair market value of
natural gas commodity
derivatives at the FortisBC
Energy companies.
----------------------------------------------------------------------------
Utility capital 1,278 449 The increase primarily
assets related to: (i) utility
capital expenditures; (ii)
the acquisition of the City
of Kelowna's electrical
utility assets by FortisBC
Electric; and (iii) the
impact of foreign exchange
on the translation of US
dollar-denominated utility
capital assets. The above
increases were partially
offset by depreciation and
customer contributions.
----------------------------------------------------------------------------
Goodwill 476 20 The increase primarily
related to $14 million in
goodwill associated with the
acquisition of the City of
Kelowna's electrical utility
assets by FortisBC Electric.
----------------------------------------------------------------------------
Accounts 102 (221) The decrease was mainly due
payable and to: (i) lower accounts
other current payable associated with
liabilities transmission-connected
projects and the timing of
Alberta Electric System
Operator payments for 2012
transmission costs at
FortisAlberta; (ii) the
timing of payments for trade
accounts payable and other
taxes payable at the
FortisBC Energy companies;
(iii) the change in the fair
market value of natural gas
commodity derivatives at the
FortisBC Energy companies;
(iv) the enactment of higher
deductions associated with
Part VI.1 tax, resulting in
the reversal of
approximately $23 million in
income tax liabilities; and
(v) lower amounts owing for
purchased power at
Newfoundland Power
associated with seasonality
of operations. The decrease
was partially offset by an
increase in 2013
transmission costs payable
at FortisAlberta.
----------------------------------------------------------------------------
Regulatory 158 1 The increase in regulatory
liabilities - liabilities was not
current and significant.
long-term
----------------------------------------------------------------------------
Long-term debt 533 686 The increase was driven by:
(including (i) higher committed credit
current facility borrowings at the
portion) Corporation to finance a
portion of the acquisition
of CH Energy Group; (ii) the
issue of $150 million
unsecured debentures at
FortisAlberta; (iii) higher
committed credit facility
borrowings at FortisBC
Electric, mainly associated
with the acquisition of the
City of Kelowna's electrical
utility assets; (iv) the
issue of US$50 million
unsecured debentures at
Caribbean Utilities; and (v)
the impact of foreign
exchange on the translation
of US-dollar denominated
debt. The above-noted
increases were partially
offset by regularly
scheduled debt repayments.
----------------------------------------------------------------------------
Deferred income 271 90 The increase was driven by
tax tax timing differences
liabilities - related mainly to capital
current and expenditures at the
long-term regulated utilities.
----------------------------------------------------------------------------
Other 185 (15) The decrease in other
Liabilities liabilities was not
significant.
----------------------------------------------------------------------------
Shareholders' - 817 The increase primarily
equity related to: (i) the
(before non- conversion of Subscription
controlling Receipts into common shares
interests) in June 2013 for net after-
tax proceeds of $567 million
to finance a portion of the
acquisition of CH Energy
Group; (ii) the issuance of
First Preference Shares,
Series K in July 2013 for
net after-tax proceeds of
$244 million; (iii) net
earnings attributable to
common equity shareholders
for the nine months ended
September 30, 2013, less
dividends declared on common
shares; and (iv) the
issuance of common shares
under the Corporation's
Dividend Reinvestment Plan.
The above-noted increases
were partially offset by the
redemption of First
Preference Shares, Series C
in July 2013 for $125
million.
----------------------------------------------------------------------------
Non-controlling - 45 The increase was driven by
interests advances from the 49% non-
controlling interests in the
Waneta Expansion Limited
Partnership ("Waneta
Partnership").
----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the
three and nine months ended September 30, 2013, as compared to the same periods
in 2012, followed by a discussion of the nature of the variances in cash flows.
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of
Period 267 231 36 154 87 67
Cash Provided by (Used
in):
Operating Activities 102 221 (119) 680 804 (124)
Investing Activities (249) (277) 28 (1,834) (761) (1,073)
Financing Activities 35 (28) 63 1,155 17 1,138
----------------------------------------------------------------------------
Cash, End of Period 155 147 8 155 147 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities was $119 million
lower for the quarter and $124 million lower year to date compared to the same
periods last year. The decreases were primarily due to unfavourable changes in
working capital at FortisAlberta and unfavourable changes in long-term
regulatory deferral accounts at the FortisBC Energy companies. The decreases
were partially offset by: (i) higher earnings and the collection from customers
of regulator-approved increases in depreciation and amortization; (ii)
favourable changes in working capital at Maritime Electric in the first quarter
of 2013; and (iii) cash proceeds received in the second quarter of 2013 on the
settlement of the expropriation matters associated with the Exploits
Partnership.
Investing Activities: Cash used in investing activities was $28 million lower
quarter over quarter, primarily due to lower capital expenditures related to the
non-regulated Waneta Expansion and at FortisAlberta and the FortisBC Energy
companies. The decrease was partially offset by capital spending at Central
Hudson in the third quarter of 2013.
Cash used in investing activities was $1,073 million higher year to date
compared to the same period last year. The increase was primarily due to the
acquisition of CH Energy Group in June 2013 for a net cash purchase price of
$1,019 million and FortisBC Electric's acquisition of electrical utility assets
of the City of Kelowna in March 2013 for approximately $55 million. Higher
capital expenditures at the regulated utilities, including capital spending at
Central Hudson in the third quarter of 2013, and Fortis Properties was partially
offset by lower capital expenditures related to the non-regulated Waneta
Expansion.
Financing Activities: Cash provided by financing activities was $35 million for
the third quarter compared to cash used in financing activities of $28 million
for the same period last year. The change quarter over quarter was primarily due
to the issuance of preference shares in July 2013 and higher proceeds from
long-term debt, partially offset by higher repayments under committed credit
facilities classified as long term and the redemption of preference shares in
July 2013.
Cash provided by financing activities was $1,138 million higher year to date
compared to the same period last year. The increase was primarily due to the
issuance of common shares and borrowings under the Corporation's committed
credit facility in connection with the acquisition of CH Energy Group, combined
with the issuance of preference shares in July 2013 and higher proceeds from
long-term debt. The increase was partially offset by the redemption of
preference shares in July 2013 and lower advances from non-controlling
interests.
In May 2013 Caribbean Utilities issued 15-year US$10 million 3.34% and 20-year
US$40 million 3.54% senior unsecured notes. The proceeds were used to repay
short-term borrowings and to finance capital expenditures.
In September 2013 FortisAlberta issued 30-year $150 million 4.85% unsecured
debentures. The net proceeds are being used to repay credit facility borrowings,
to fund future capital expenditures and for general corporate purposes.
Repayments of long-term debt and capital lease and finance obligations and net
(repayments) borrowings under committed credit facilities for the quarter and
year to date compared to the same periods last year are summarized in the
following tables.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
(Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy
Companies (2) - (2) (28) (18) (10)
Caribbean Utilities - - - (17) (13) (4)
Fortis Properties (1) - (1) (21) (24) 3
Other (2) - (2) (4) (2) (2)
----------------------------------------------------------------------------
Total (5) - (5) (70) (57) (13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended
September 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta (94) (22) (72) - (13) 13
FortisBC Electric 11 (17) 28 44 (9) 53
Newfoundland
Power (20) (20) - 2 8 (6)
Corporate (84) 50 (134) 465 235 230
----------------------------------------------------------------------------
Total (187) (9) (178) 511 221 290
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Borrowings under credit facilities by the utilities are primarily in support of
their capital expenditure programs and/or for working capital requirements.
Repayments are primarily financed through the issuance of long-term debt, cash
from operations and/or equity injections from Fortis. From time to time,
proceeds from preference share, common share and long-term debt offerings are
used to repay borrowings under the Corporation's committed credit facility. The
borrowings under the Corporation's committed credit facility in 2013 were
incurred to finance a portion of the acquisition of CH Energy Group, to support
the construction of the Waneta Expansion and to finance an equity injection into
FortisAlberta in support of energy infrastructure investment.
Advances from non-controlling interests in the Waneta Partnership of
approximately $42 million were received in the first half of 2013 to finance
capital spending related to the Waneta Expansion, compared to $14 million and
$70 million received during the third quarter and year-to-date periods in 2012,
respectively. In January 2012 advances of approximately $12 million were
received from two First Nations bands, representing their 15% equity investment
in the LNG storage facility on Vancouver Island.
Proceeds from the issuance of common shares were $592 million year-to-date 2013,
compared to $12 million for the same period last year. The increase was
primarily due to the issuance of 18.5 million common shares in June 2013, as a
result of the conversion of the Subscription Receipts on closing of the CH
Energy Group acquisition, for proceeds of approximately $567 million, net of
after-tax expenses. The increase also reflected a higher number of common shares
issued under the Corporation's dividend reinvestment and employee share purchase
plans.
In July 2013 Fortis issued 10 million First Preference Shares, Series K for
gross proceeds of $250 million. The proceeds were used to redeem all of the
Corporation's First Preference Shares, Series C in July 2013 for $125 million,
to repay a portion of credit facility borrowings, and for other general
corporate purposes.
Common share dividends paid in the third quarter of 2013 were $49 million, net
of $17 million of dividends reinvested, compared to $42 million, net of $15
million of dividends reinvested, paid in the same quarter of 2012. Common share
dividends paid year-to-date 2013 were $134 million, net of $51 million of
dividends reinvested, compared to $128 million, net of $43 million of dividends
reinvested, paid year-to-date 2012. The dividend paid per common share for each
of the first, second and third quarters of 2013 was $0.31 compared to $0.30 for
each of the first, second and third quarters of 2012. The weighted average
number of common shares outstanding for the third quarter and year to date was
212.0 million and 199.1 million, respectively, compared to 190.2 million and
189.6 million, respectively, for the same periods in 2012.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third
parties in each of the next five years and for periods thereafter, as at
September 30, 2013, are outlined in the following table. A detailed description
of the nature of the obligations is provided in the 2012 Annual MD&A and below,
where applicable.
----------------------------------------------------------------------------
Contractual Obligations
(Unaudited) Due Due
As at September 30, 2013 within Due in Due in Due in Due in after
($ millions) Total 1 year year 2 year 3 year 4 year 55 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 7,119 369 605 377 58 608 5,102
Government loan obligations 15 - 10 5 - - -
Capital lease and finance
obligations 2,551 47 47 49 49 50 2,309
Interest obligations on
long-term debt 7,112 385 357 328 308 298 5,436
Gas purchase contract
obligations (1) 405 284 51 19 16 12 23
Power purchase obligations:
Central Hudson (2) 42 20 4 3 3 3 9
FortisBC Electric 35 14 11 6 3 1 -
FortisOntario 320 46 50 51 52 53 68
Maritime Electric 111 40 40 17 1 1 12
Capital cost (3) 542 20 19 21 19 21 442
Construction and
maintenance projects (4) 119 61 33 14 4 3 4
Operating lease obligations 21 4 4 3 3 3 4
Waneta Partnership
promissory note 72 - - - - - 72
Joint-use asset and shared
service agreements 61 3 3 3 3 3 46
Defined benefit pension
funding contributions 57 23 15 12 4 - 3
Performance Share Unit Plan
obligations 8 2 2 4 - - -
Other 16 12 - - - - 4
----------------------------------------------------------------------------
Total 18,606 1,330 1,251 912 523 1,056 13,534
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Gas purchase contract obligations at the FortisBC Energy companies are
based on index prices as at September 30, 2013. Gas purchase contract
obligations at Central Hudson are based on tariff rates as at
September 30, 2013.
(2) Central Hudson has entered into agreements with Entergy Nuclear Power
Marketing, LLC to purchase electricity, and not capacity, on a unit-
contingent basis at defined prices from January 1, 2011 through
December 31, 2013. Central Hudson must also acquire sufficient peak
load capacity to meet the peak load requirements of its full-service
customers. This capacity requirement is met through contracts with
capacity providers, purchases from the NYISO capacity market and the
Company's own generating capacity.
(3) Maritime Electric has entitlement to approximately 4.7% of the output
from Point Lepreau for the life of the unit. As part of its
entitlement, Maritime Electric is required to pay its share of the
capital and operating costs of the unit. A major refurbishment of
Point Lepreau that began in 2008 was completed and the facility
returned to service in November 2012. The refurbishment is expected to
extend the facility's estimated life an additional 27 years and, as a
result, the total estimated capital cost obligation has increased
approximately $96 million from that disclosed in the 2012 Annual MD&A.
(4) Central Hudson has various purchase commitments and contracts related
to ongoing projects and operating activities.
Other contractual obligations, which are not reflected in the above table, did
not materially change from those disclosed in the 2012 Annual MD&A, except as
follows.
In May 2013 FortisBC Electric entered into a new Power Purchase Agreement
("PPA") with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of
associated energy annually for a 20-year term beginning October 1, 2013. This
new PPA does not change the basic parameters of the BC Hydro PPA, which expired
on September 30, 2013. An executed version of the PPA was submitted by BC Hydro
to the BCUC in May 2013 and is pending regulatory approval. In the interim
period until the new PPA is approved by the BCUC, FortisBC Electric and BC Hydro
have agreed to continue under the terms of the expired BC Hydro PPA. Power
purchases in the interim are approved for recovery in customer rates. The power
purchases from the new PPA are expected to be recovered in customer rates.
For a discussion of the nature and amount of the Corporation's consolidated
capital expenditure program, that is not included in the preceding Contractual
Obligations table, refer to the "Capital Expenditure Program" section of this
MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to enable the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt offerings. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 45%
equity, including preference shares, and 55% debt, as well as investment-grade
credit ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in each of
the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
September 30, 2013 December 31, 2012
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
and finance obligations
(net of cash) 7,503 55.9 6,317 55.3
Preference shares 1,229 9.2 1,108 9.7
Common shareholders' equity 4,688 34.9 3,992 35.0
----------------------------------------------------------------------------
Total (1) 13,420 100.0 11,417 100.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes amounts related to non-controlling interests
The change in the capital structure was primarily due to the financing of the
acquisition of CH Energy Group, including: (i) the conversion of Subscription
Receipts into common shares for $567 million, net of after-tax expenses; (ii)
debt assumed upon acquisition; and (iii) higher borrowings under the
Corporation's committed credit facility, to initially finance the remaining
portion of the acquisition. The capital structure was also impacted by: (i) an
increase in total debt, mainly in support of energy infrastructure investment;
(ii) the issuance of First Preference Shares, Series K, partially offset by the
redemption of First Preference Shares, Series C; (iii) net earnings attributable
to common equity shareholders for the nine months ended September 30, 2013, less
dividends declared on common shares; and (iv) the issuance of common shares
under the Corporation's Dividend Reinvestment Plan.
Excluding capital lease and finance obligations, the Corporation's capital
structure as at September 30, 2013 was 54.4% debt, 9.5% preference shares and
36.1% common shareholders' equity (December 31, 2012 - 53.6% debt, 10.1%
preference shares and 36.3% common shareholders' equity).
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
In February 2013 S&P and DBRS affirmed the Corporation's debt credit ratings.
The above-noted credit ratings reflect the Corporation's business-risk profile
and diversity of its operations, the stand-alone nature and financial separation
of each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis. The credit ratings also reflect the Corporation's financing
of the acquisition of CH Energy Group and the expected completion of the Waneta
Expansion on time and on budget.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $809 million in gross consolidated capital expenditures by
segment year-to-date 2013 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date September 30, 2013
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regulated Regulated
FortisBC Electric Electric
Energy Central Fortis FortisBC Newfoundland Utilities - Utilities -
Companies Hudson Alberta Electric Power Canadian Caribbean
----------------------------------------------------------------------------
142 28 306 58 63 40 35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
-----------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited)
(1)
Year-to-Date September 30, 2013
($ millions)
-----------------------------------------------------
-----------------------------------------------------
Non- Non-
FortisBC Total Regulated - Regulated -
Energy Regulated Fortis Non-
Companies Utilities Generation Utility Total
-----------------------------------------------------
142 672 101 36 809
-----------------------------------------------------
-----------------------------------------------------
(1) Relates to cash payments to acquire or construct utility and non-
utility capital assets and intangible assets, as reflected on the
consolidated statement of cash flows. Excludes capitalized
depreciation and amortization and non-cash equity component of AFUDC.
Planned capital expenditures are based on detailed forecasts of energy demand,
weather, cost of labour and materials, as well as other factors, including
economic conditions, which could change and cause actual expenditures to differ
from those forecast.
Gross consolidated capital expenditures for 2013 are forecast to be
approximately $1.2 billion. This represents a decrease of approximately $150
million from the original 2013 forecast disclosed in the 2012 Annual MD&A. The
decrease is primarily due to the non-regulated Waneta Expansion, FortisBC
Electric and FAES, partially offset by Central Hudson.
Lower forecast capital expenditures related to the Waneta Expansion for 2013 are
primarily due to the timing of payments. Capital expenditures at FortisBC
Electric are expected to be lower than the original forecast for 2013 as a
result of labour disruptions. For further information on labour relations refer
to the "Business Risk Management" section of this MD&A. Due to the uncertainty
of the timing of alternative energy projects at FAES, capital expenditures for
2013 are delayed and are expected to be lower than the original forecast.
Capital expenditures for 2013 now include approximately $59 million forecast at
Central Hudson from the date of acquisition.
Construction of the $900 million Waneta Expansion is ongoing, with an additional
$98 million invested year-to-date 2013. Approximately $534 million has been
invested in the Waneta Expansion since construction began late in 2010. Key
construction activities year-to-date 2013 include the ongoing civil construction
of the powerhouse and intake, installation of the turbine components,
installation of ancillary mechanical and electrical powerhouse services, and
most notably, the encapsulating of the scrollcase in concrete. During the third
quarter, the generator step-up transformers were received onsite for assembly.
The key offsite activity in the third quarter of 2013 was the successful
completion of the manufacturing of the first turbine runner and turbine
operating mechanism.
Over the five-year period 2013 through 2017, gross consolidated capital
expenditures are expected to be approximately $6 billion. The approximate
breakdown of the capital spending expected to be incurred is as follows: 53% at
Canadian Regulated Electric Utilities, driven by FortisAlberta; 21% at Canadian
Regulated Gas Utilities; 11% at Central Hudson; 4% at Caribbean Regulated
Electric Utilities; and the remaining 11% at non-regulated operations. Capital
expenditures at the regulated utilities are subject to regulatory approval. Over
the five-year period, on average annually, the approximate breakdown of the
total capital spending to be incurred is as follows: 36% to meet customer
growth, 41% for sustaining capital expenditures, and 23% for facilities,
equipment, vehicles, information technology and other assets.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest
costs will generally be paid out of subsidiary operating cash flows, with
varying levels of residual cash flows available for subsidiary capital
expenditures and/or dividend payments to Fortis. Borrowings under credit
facilities may be required from time to time to support seasonal working capital
requirements. Cash required to complete subsidiary capital expenditure programs
is also expected to be financed from a combination of borrowings under credit
facilities, equity injections from Fortis and long-term debt offerings.
The Corporation's ability to service its debt obligations and pay dividends on
its common shares and preference shares is dependent on the financial results of
the operating subsidiaries and the related cash payments from these
subsidiaries. Certain regulated subsidiaries may be subject to restrictions that
may limit their ability to distribute cash to Fortis.
Cash required of Fortis to support subsidiary capital expenditure programs and
finance acquisitions is expected to be derived from a combination of borrowings
under the Corporation's committed corporate credit facility and proceeds from
the issuance of common shares, preference shares and long-term debt. Depending
on the timing of cash payments from the subsidiaries, borrowings under the
Corporation's committed corporate credit facility may be required from time to
time to support the servicing of debt and payment of dividends.
As at September 30, 2013, management expects consolidated long-term debt
maturities and repayments to average approximately $335 million annually over
the next five years, excluding borrowings under the Corporation's committed
credit facility which were subsequently replaced with long-term financing. The
combination of available credit facilities and relatively low annual debt
maturities and repayments will provide the Corporation and its subsidiaries with
flexibility in the timing of access to capital markets.
In May 2012 Fortis filed a short-form base shelf prospectus under which Fortis
may offer, from time to time during the 25-month period from May 10, 2012, by
way of a prospectus supplement, common shares, preference shares, subscription
receipts and/or unsecured debentures in the aggregate amount of up to $1.3
billion (or the equivalent in US dollars or other currencies). The base shelf
prospectus provides the Corporation with flexibility to access securities
markets in a timely manner.
Through prospectus supplements filed under its base shelf prospectus, Fortis
offered and sold: (i) approximately $601 million of Subscription Receipts in
June 2012 (refer to the "Significant Items" section in this MD&A); (ii) $200
million First Preference Shares, Series J in November 2012; and (iii) $250
million First Preference Shares, Series K in July 2013 (refer to the
"Significant Items" section in this MD&A). The remaining amount available under
the base shelf prospectus is approximately $250 million.
In July 2013 FortisBC Electric filed a short-form base shelf prospectus to
establish a Medium-Term Note ("MTN") Debentures Program and entered into a
dealer agreement with certain affiliates of a group of Canadian Chartered Banks.
Upon filing the shelf prospectus, the Company may, from time to time during the
25-month life of the base shelf prospectus, issue MTN Debentures in an aggregate
principal amount of up to $300 million. The establishment of the MTN Debentures
Program has been approved by the BCUC.
In October 2013 FortisAlberta filed a short-form base shelf prospectus under
which the Company may, from time to time during the 25-month life of the base
shelf prospectus, issue MTN Debentures in an aggregate principal amount of up to
$500 million.
Fortis and its subsidiaries were compliant with debt covenants as at September
30, 2013 and are expected to remain compliant throughout 2013.
CREDIT FACILITIES
As at September 30, 2013, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.7 billion, of which $1.9 billion was
unused, including $490 million unused under the Corporation's $1 billion
committed revolving corporate credit facility. The credit facilities are
syndicated mostly with the seven largest Canadian banks, with no one bank
holding more than 20% of these facilities. Approximately $2.6 billion of the
total credit facilities are committed facilities with maturities ranging from
2014 through 2018.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
----------------------------------------------------------------------------
Credit Facilities (Unaudited) As at
September December
Regulated Non- Corporate 30, 31,
($ millions) Utilities Regulated and Other 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit facilities 1,539 115 1,030 2,684 2,460
Credit facilities
utilized:
Short-term borrowings (111) - - (111) (136)
Long-term debt
(including current
portion) (123) - (509) (632) (150)
Letters of credit
outstanding (65) - (1) (66) (67)
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Credit facilities unused 1,240 115 520 1,875 2,107
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As at September 30, 2013 and December 31, 2012, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In January 2013 FEVI's $20 million unsecured committed non-revolving credit
facility matured and was not replaced.
In April 2013 FortisBC Electric renegotiated and amended its credit facility
agreement, resulting in an extension to the maturity of the Company's $150
million unsecured committed revolving credit facility with $100 million now
maturing in May 2016 and $50 million now maturing in May 2014. The amended
credit facility agreement contains substantially similar terms and conditions as
the previous credit facility agreement.
In April 2013 FHI extended its $30 million unsecured committed revolving credit
facility to mature in May 2014 from May 2013.
In May 2013 FortisOntario extended its $30 million unsecured revolving credit
facility to mature in June 2014 from June 2013.
In June 2013 Fortis Turks and Caicos entered into new short-term unsecured
demand credit facilities for US$21 million ($22 million), replacing its previous
US$21 million ($22 million) facilities. The new facilities are comprised of a
revolving operating credit facility of US$12 million ($12 million) and a US$9
million ($9 million) emergency standby loan. The facilities mature in June 2014,
with an option to renew annually. The new credit facilities reflect a decrease
in pricing but otherwise contain terms and conditions substantially similar to
the previous facilities.
In July 2013 FEI, FEVI and FortisAlberta amended their $500 million, $200
million and $250 million committed revolving credit facilities, resulting in
extensions to the maturity dates to August 2015, December 2015 and August 2018,
respectively, from August 2014, December 2013 and August 2016, respectively. The
new agreements contain substantially similar terms and conditions as the
previous credit facility agreements.
In August 2013 the Corporation extended its $1 billion committed revolving
corporate credit facility to mature in July 2018 from July 2015.
As at September 30, 2013, CH Energy Group had a US$100 million ($103 million)
unsecured revolving credit facility maturing in October 2015, and Central Hudson
had a US$150 million ($155 million) unsecured committed revolving credit
facility maturing in October 2016.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows.
Financial Instruments
(Unaudited) As at
September 30, 2013 December 31, 2012
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Waneta Partnership
promissory note 49 50 47 51
Long-term debt, including
current portion 7,119 8,029 5,900 7,338
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The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Partnership promissory note and certain long-term debt, the fair value is
determined by either: (i) discounting the future cash flows of the specific debt
instrument at an estimated yield to maturity equivalent to benchmark government
bonds or treasury bills, with similar terms to maturity, plus a credit risk
premium equal to that of issuers of similar credit quality; or (ii) by obtaining
from third parties indicative prices for the same or similarly rated issues of
debt of the same remaining maturities. Since the Corporation does not intend to
settle the long-term debt or promissory note prior to maturity, the excess of
the estimated fair value above the carrying value does not represent an actual
liability.
The Financial Instruments table above excludes the long-term other asset
associated with the Corporation's expropriated investment in Belize Electricity.
Due to uncertainty in the ultimate amount and ability of the Government of
Belize ("GOB") to pay appropriate fair value compensation owing to Fortis for
the expropriation of Belize Electricity, the Corporation has recorded the book
value of the expropriated investment, including foreign exchange impacts, in
long-term other assets, which totalled approximately $105 million as at
September 30, 2013 (December 31, 2012 - $104 million).
Risk Management: The Corporation's earnings from, and net investments in,
foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian
dollar exchange rate. The Corporation has effectively decreased the above-noted
exposure through the use of US dollar-denominated borrowings at the corporate
level. The foreign exchange gain or loss on the translation of US
dollar-denominated interest expense partially offsets the foreign exchange loss
or gain on the translation of the Corporation's foreign subsidiaries' earnings,
which are denominated in US dollars. The reporting currency of Central Hudson,
Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy Corporation,
Belize Electric Company Limited ("BECOL") and Griffith is the US dollar.
As at September 30, 2013, the Corporation's corporately issued US$1,044 million
(December 31, 2012 - US$557 million) long-term debt had been designated as an
effective hedge of the Corporation's foreign net investments. As at September
30, 2013, the Corporation had approximately US$549 million (December 31, 2012 -
US$17 million) in foreign net investments remaining to be hedged. Both the
Corporation's US dollar-denominated long-term debt and foreign net investments
as at September 30, 2013 were significantly impacted by the CH Energy Group
acquisition. Foreign currency exchange rate fluctuations associated with the
translation of the Corporation's corporately issued US dollar-denominated
borrowings designated as effective hedges are recorded in other comprehensive
income and serve to help offset unrealized foreign currency exchange gains and
losses on the net investments in foreign subsidiaries, which gains and losses
are also recorded in other comprehensive income.
Effective from June 20, 2011, the Corporation's asset associated with its
expropriated investment in Belize Electricity does not qualify for hedge
accounting as Belize Electricity is no longer a foreign subsidiary of Fortis. As
a result, foreign exchange gains and losses on the translation of the long-term
other asset associated with Belize Electricity are recognized in earnings. The
Corporation recognized in earnings a foreign exchange loss of $2 million for the
three months ended and a foreign exchange gain of $3 million for the nine months
ended September 30, 2013 ($3 million foreign exchange loss for the three and
nine months ended September 30, 2012).
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel, electricity and
natural gas prices through the use of derivative instruments. The Corporation
and its subsidiaries do not hold or issue derivative instruments for trading
purposes. As at September 30, 2013, the Corporation's derivative contracts
consisted of fuel option contracts, electricity swap contracts, natural gas swap
and option contracts, and gas purchase contract premiums. The fuel option
contracts are held by Caribbean Utilities. Electricity swap contracts are held
by Central Hudson. Gas swaps and options and gas purchase contract premiums are
held by the FortisBC Energy companies and Central Hudson.
The following table summarizes the Corporation's derivative instruments.
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Derivative Instruments (Unaudited) As at
September 30, December 31,
2013 2012
Carrying Carrying
(Liability) Asset Number of Volume Value (2) Value (2)
Maturity Contracts (1) ($ millions) ($ millions)
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Fuel option
contracts (3) 2013 2 1 - (1)
Electricity swap
contracts 2017 5 2,850 1 -
Natural gas
commodity
derivatives:
Gas swaps and
options 2014 49 10 (23) (51)
Gas purchase
contract
premiums 2015 75 83 - (8)
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(1) The volume for fuel option contracts is reported in millions of
imperial gallons; electricity swap contracts in GWh; and natural gas
commodity derivatives in PJ.
(2) Carrying value is estimated fair value. The (liability) asset
represents the gross derivatives balance.
(3) The carrying value of the fuel option contracts was less than $1
million as at September 30, 2013.
The fuel option contracts are used by Caribbean Utilities to reduce the impact
of volatility in fuel prices on customer rates, as approved by the regulator
under the Company's Fuel Price Volatility Management Program. The fair value of
the fuel option contracts reflects only the value of the heating oil derivative
and not the offsetting change in the value of the underlying future purchases of
heating oil and was calculated using published market prices for heating oil or
similar commodities where appropriate. The fuel option contracts matured in
October 2013. Approximately 30% of the Company's annual diesel fuel requirements
are under fuel hedging arrangements.
The electricity swap contracts and natural gas commodity derivatives are used by
Central Hudson to minimize commodity price volatility for electricity and
natural gas purchases for the Company's full-service customers by fixing the
effective purchase price for the defined commodities. The fair values of the
electricity swap contracts and natural gas commodity derivatives were calculated
using forward pricing provided by independent third parties.
The natural gas commodity derivatives are used by the FortisBC Energy companies
to fix the effective purchase price of natural gas, as the majority of the
natural gas supply contracts have floating, rather than fixed, prices. The fair
value of the natural gas commodity derivatives was calculated using the present
value of cash flows based on market prices and forward curves for the commodity
cost of natural gas.
The price risk-management strategy of the FortisBC Energy companies aims to
improve the likelihood that natural gas prices remain competitive, mitigate gas
price volatility on customer rates and reduce the risk of regional price
discrepancies. As directed by the regulator in 2011, the FortisBC Energy
companies have suspended their commodity hedging activities with the exception
of certain limited swaps as permitted by the regulator. The existing hedging
contracts will continue in effect through to their maturity and the FortisBC
Energy companies' ability to fully recover the commodity cost of gas in customer
rates remains unchanged.
The fair values of the fuel option contracts, electricity swap contracts, and
natural gas commodity derivatives are estimates of the amounts that the
utilities would receive or have to pay to terminate the outstanding contracts as
at the balance sheet dates.
The changes in the fair values of the fuel option contracts, electricity swap
contracts and natural gas commodity derivatives are deferred as a regulatory
asset or liability for recovery from, or refund to, customers in future rates,
as permitted by the regulators. The fair values of the derivative instruments
were recorded in accounts payable and other current liabilities as at September
30, 2013 and December 31, 2012.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $66 million as at
September 30, 2013 (December 31, 2012 - $67 million), the Corporation had no
off-balance sheet arrangements that are reasonably likely to materially affect
liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
Year-to-date 2013, the business risks of the Corporation were generally
consistent with those disclosed in the Corporation's 2012 Annual MD&A, including
certain risks, as disclosed below, and an update to those risks, where
applicable.
Regulatory Risk: The allowed ROE and capital structure at Newfoundland Power
have been set for 2013 through 2015 and remain unchanged from 2012. At FEI, the
allowed ROE and capital structure have been set for 2013, resulting in a
decrease of 75 basis points in the allowed ROE and a reduction in the common
equity component of capital structure to 38.5% from 40% as compared to 2012.
Final allowed ROEs and capital structures for 2013 remain outstanding for
FortisAlberta, FortisBC Electric, FEVI and FEWI. The results of cost of capital
proceedings could materially impact the earnings of the above-noted utilities.
PBR commenced at FortisAlberta for a five-year term, beginning January 1, 2013.
In March 2013 interim distribution electricity rates under PBR were approved by
the AUC, in addition to the recovery, on an interim basis, of 60% of the revenue
requirement associated with 2013 capital tracker expenditures applied for by
FortisAlberta. While the AUC's 2012 PBR decision provides for a capital tracker
mechanism to address recovery of certain capital expenditures outside of the PBR
formula, the mechanism has yet to be tested to confirm its applicability to
FortisAlberta's capital program. Final decisions on FortisAlberta's rates are
expected in the fourth quarter of 2013.
For further information, refer to the "Material Regulatory Decisions and
Applications" section of this MD&A.
Acquisition of CH Energy Group: As a result of the closing of the CH Energy
Group acquisition on June 27, 2013, the risks associated with the completion of
the transaction are no longer applicable.
Expropriation of Shares in Belize Electricity: A decision is pending from the
Belize Court of Appeal regarding the Corporation's appeal of the Belize Supreme
Court's dismissal of the Corporation's claim filed in October 2011 challenging
the constitutionality of the expropriation of the Corporation's investment in
Belize Electricity.
Fortis believes it has a strong, well-positioned case before the Belize Courts
supporting the unconstitutionality of the expropriation. There exists, however,
a reasonable possibility that the outcome of the litigation may be unfavourable
to the Corporation and the amount of compensation otherwise to be paid to Fortis
under the legislation expropriating Belize Electricity could be lower than the
book value of the Corporation's expropriated investment in Belize Electricity.
The book value was $105 million, including foreign exchange impacts, as at
September 30, 2013 (December 31, 2012 - $104 million). If the expropriation is
held to be unconstitutional, it is not determinable at this time as to the
nature of the relief that would be awarded to Fortis, for example: (i) the
ordering of the return of the shares to Fortis and/or award of damages; or (ii)
the ordering of compensation to be paid to Fortis for the unconstitutional
expropriation of the shares. Based on presently available information, the $105
million long-term other asset is not deemed impaired as at September 30, 2013.
Fortis will continue to assess for impairment each reporting period based on
evaluating the outcomes of court proceedings and/or compensation settlement
negotiations. As well as continuing the constitutional challenge of the
expropriation, Fortis is also pursuing alternative options for obtaining fair
compensation, including compensation under the Belize/United Kingdom Bilateral
Investment Treaty.
Fortis continues to control and consolidate the financial statements of BECOL,
the Corporation's indirect wholly owned non-regulated hydroelectric generating
subsidiary in Belize. As at October 31, 2013, Belize Electricity owed BECOL US$2
million for overdue energy purchases, representing approximately 10% of BECOL's
annual sales to Belize Electricity. In accordance with long-standing agreements,
the GOB guarantees the payment of Belize Electricity's obligations to BECOL.
Capital Resources and Liquidity Risk - Credit Ratings: The Corporation's credit
ratings were affirmed by S&P and DBRS in February 2013. Year-to-date 2013, the
following changes were made to the credit ratings of the Corporation's
utilities: (i) S&P updated Maritime Electric's debt credit rating from 'A-
stable' to 'A stable' in February 2013; (ii) Moody's Investors Service
("Moody's"), in June 2013, affirmed the long-term credit ratings of FHI, FEI,
FEVI and FortisBC Electric, and changed the rating outlooks to negative from
stable; and (iii) Fitch Ratings and Moody's, in July 2013, affirmed Central
Hudson's debt credit ratings at 'A stable' and 'A3 stable', respectively, and
S&P also affirmed the Company's debt credit rating at 'A' and removed it from
'credit watch with negative implications'.
Defined Benefit Pension and OPEB Plan Assets: As at September 30, 2013, the fair
value of the Corporation's consolidated defined benefit pension and OPEB plan
assets was $1,563 million, up $695 million or 80%, from $868 million as at
December 31, 2012. Of the increase from December 31, 2012, approximately $652
million, or 75%, was due to the acquisition of CH Energy Group.
Labour Relations: The collective agreement between the FortisBC Energy companies
and the Canadian Office and Professional Employees Union ("COPE"), Local 378,
expired on March 31, 2012. COPE represents employees in specified occupations in
the areas of administration and operations support. A new three-year collective
agreement, expiring on March 31, 2015, was reached in March 2013.
The collective agreement between FortisBC Electric and the International
Brotherhood of Electrical Workers ("IBEW"), Local 213, expired on January 31,
2013. IBEW, Local 213, represents employees in specified occupations in the
areas of generation and T&D. The parties have been negotiating since January
2013. The IBEW, Local 213 served the Company 72 hours' strike notice on March
13, 2013 and commenced partial job action on May 16, 2013. FortisBC Electric is
operating under the most recent essential services order issued by the Labour
Relations Board of British Columbia in September 2013. The essential services
order outlines these services that are necessary to prevent immediate and
serious danger to the health, safety or welfare of the citizens of British
Columbia. FortisBC Electric activated the essential services order to provide
certainty and stability in the delivery of electricity service. The Company is
committed to reaching a fair and reasonable agreement that balances the needs of
its employees and customers. Approximately 200 of FortisBC Electric's employees
are members of the IBEW, Local 213.
Power Supply Contract: FortisBC Electric has a power supply sale agreement with
BC Hydro for the sale of electricity generated from its non-regulated Walden
Power Partnership hydroelectric generating facility, which has a net book value
of approximately $10 million as at September 30, 2013. The agreement is set to
expire in the fourth quarter of 2013. Accordingly, the Company is exposed to the
risk that it will not be able to sell the power from this facility beyond 2013
on similar terms.
CHANGES IN ACCOUNTING POLICIES
The new US GAAP accounting pronouncements that are applicable to, and were
adopted by, Fortis, effective January 1, 2013, are described as follows.
Disclosures About Offsetting Assets and Liabilities
The Corporation adopted the amendments to Accounting Standards Codification
("ASC") Topic 210, Balance Sheet - Disclosures About Offsetting Assets and
Liabilities as outlined in Accounting Standards Update ("ASU") No. 2011-11 and
ASU No. 2013-01. The amendments improve the transparency of the effect or
potential effect of netting arrangements on a company's financial position by
expanding the level of disclosures required by entities for such arrangements.
The above-noted amendments were applied retrospectively and did not materially
impact the Corporation's interim consolidated financial statements for the three
and nine months ended September 30, 2013.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The Corporation adopted the amendments to ASC Topic 220, Other Comprehensive
Income - Reporting of Amounts Reclassified Out of Accumulated Other
Comprehensive Income ("AOCI") as outlined in ASU No. 2013-02. The amendments
improve the reporting of reclassifications out of AOCI and require entities to
report, in one place, information about reclassifications out of AOCI and to
present details of the reclassifications in the disclosure for changes in AOCI
balances. The amendments were applied by the Corporation prospectively
commencing on January 1, 2013 and did not materially impact the Corporation's
interim consolidated financial statements for the three and nine months ended
September 30, 2013.
FUTURE ACCOUNTING PRONOUNCEMENTS
Obligations Resulting from Joint and Several Liability Arrangements
In February 2013, the Financial Accounting Standards Board ("FASB") issued ASU
No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements
for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The
objective of this update is to provide guidance for the recognition,
measurement, and disclosure of obligations resulting from joint and several
liability arrangements for which the total amount of the obligation is fixed at
the reporting date. This accounting update is effective for annual and interim
periods beginning on or after December 15, 2013 and is to be applied
retrospectively. Fortis does not expect that the adoption of this update will
have a material impact on its consolidated financial statements.
Parent's Accounting for the Cumulative Translation Adjustment
In March 2013, FASB issued ASU No. 2013-5, Parent's Accounting for the
Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or
Groups of Assets within a Foreign Entity or of an Investment in a Foreign
Entity. This update applies to the release of the cumulative translation
adjustment into net earnings when a parent either sells a part or all of its
investment in a foreign entity or no longer holds a controlling financial
interest in a subsidiary or group of assets within a foreign entity. This
accounting update is effective for annual and interim periods beginning on or
after December 15, 2013 and is to be applied prospectively. Fortis does not
expect that the adoption of this update will have a material impact on its
consolidated financial statements.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax
Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax
Credit Carryforward Exists. This amendment provides guidance on the presentation
of unrecognized tax benefits when net operating loss carryforwards, similar tax
losses, or tax credit carryforwards exist and is intended to better reflect the
manner in which an entity would settle any additional income taxes that would
result from the disallowance of a tax position when net operating loss
carryforwards, similar tax losses, or tax credit carryforwards exist. This
accounting update is effective for annual and interim periods beginning on or
after December 15, 2013 and is to be applied prospectively. Fortis does not
expect that the adoption of this update will have a material impact on its
consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial
statements in accordance with US GAAP requires management to make estimates and
judgments that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenue and expenses during the
reporting periods. Estimates and judgments are based on historical experience,
current conditions and various other assumptions believed to be reasonable under
the circumstances. Additionally, certain estimates and judgments are necessary
since the regulatory environments in which the Corporation's utilities operate
often require amounts to be recorded at estimated values until these amounts are
finalized pursuant to regulatory decisions or other regulatory proceedings. 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 recognized in earnings in the period in which they become
known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates year-to-date 2013 from those
disclosed in the 2012 Annual MD&A.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with the ordinary course of business
operations. Management believes that the amount of liability, if any, from these
actions would not have a material effect on the Corporation's consolidated
financial position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed settlement
agreement with counsel to plaintiff shareholders pertaining to several
complaints, which named Fortis and other defendants, which were filed in, or
transferred to, the Supreme Court of the State of New York, County of New York,
relating to the acquisition of CH Energy Group by Fortis. The complaints
generally alleged that the directors of CH Energy Group breached their fiduciary
duties in connection with the acquisition and that CH Energy Group, Fortis,
FortisUS Inc. and Cascade Acquisition Sub Inc. aided and abetted that breach.
The settlement agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from Canada Revenue Agency ("CRA") for additional taxes related to
the taxation years 1999 through 2003. The exposure has been fully provided for
in the consolidated financial statements. A settlement was reached with CRA in
the second quarter of 2013 resulting in the release of income tax provisions of
approximately $5 million.
In April 2013 FHI and Fortis were named as defendants in an action in the
British Columbia Supreme Court by the Coldwater Indian Band ("Band"). The claim
is in regard to interests in a pipeline right of way on reserve lands. The
pipeline on the right of way was transferred by FHI (then Terasen Inc.) to
Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of
way and claims damages for wrongful interference with the Band's use and
enjoyment of reserve lands. The outcome cannot be reasonably determined and
estimated at this time and, accordingly, no amount has been accrued in the
interim unaudited consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices
Code and negligence relating to a forest fire near Vaseux Lake in 2003, prior to
the acquisition of FortisBC Electric by Fortis, and has filed and served a writ
and statement of claim against FortisBC Electric dated August 2, 2005. The
Government of British Columbia has now disclosed that its claim includes
approximately $15 million in damages as well as pre-judgment interest, but that
it has not fully quantified its damages. FortisBC Electric and its insurers
continue to defend the claim by the Government of British Columbia. The outcome
cannot be reasonably determined and estimated at this time and, accordingly, no
amount has been accrued in the interim unaudited consolidated financial
statements.
The Government of British Columbia filed a claim in the British Columbia Supreme
Court in June 2012 claiming on its behalf, and on behalf of approximately 17
homeowners, damages suffered as a result of a landslide caused by a dam failure
in Oliver, British Columbia in 2010. The Government of British Columbia alleges
in its claim that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government of British
Columbia estimates its damages and the damages of the homeowners, on whose
behalf it is claiming, to be approximately $15 million. While FortisBC Electric
has not been served, the utility has retained counsel and has notified its
insurers. The outcome cannot be reasonably determined and estimated at this time
and, accordingly, no amount has been accrued in the interim unaudited
consolidated financial statements.
Central Hudson
Danskammer Point Steam Electric Generating Station
In 1999, the New York State Attorney General alleged that Central Hudson may
have constructed, and continued to operate, major modifications to the
Danskammer Point Steam Electric Generating Station ("Danskammer Plant") without
obtaining certain requisite pre-construction permits. In March 2000, the
Environmental Protection Agency assumed responsibility for the investigation.
Central Hudson believes any permits required for these projects were obtained in
a timely manner. The Company sold the Danskammer Plant to Dynegy Inc. in January
2001. While Central Hudson could have retained liability after the sale,
depending on the type of remedy, the Company believes that the statutes of
limitation relating to any alleged violation of air emissions rules have lapsed.
Former MGP Facilities
Central Hudson and its predecessors owned and operated MGPs to serve their
customers' heating and lighting needs. These plants manufactured gas from coal
and oil beginning in the mid to late 1800's with all sites ceasing operations by
the 1950's. This process produced certain by-products that may pose risks to
human health and the environment.
The New York State Department of Environmental Conservation ("DEC"), which
regulates the timing and extent of remediation of MGP sites in New York State,
has notified Central Hudson that it believes the Company or its predecessors at
one time owned and/or operated MGPs at seven sites in Central Hudson's franchise
territory. The DEC has further requested that the Company investigate and, if
necessary, remediate these sites under a Consent Order, Voluntary Clean-up
Agreement, or Brownfield Clean-up Agreement. Central Hudson accrues for
remediation costs based on the amounts that can be reasonably estimated. As at
September 30, 2013, an obligation of US$8 million was recognized in respect of
MGPs remediation and, based upon cost model analysis completed in 2012, it is
estimated, with a 90% confidence level, that total costs to remediate these
sites over the next 30 years will not exceed US$152 million.
Central Hudson has notified its insurers and intends to seek reimbursement from
insurers for remediation, where coverage exists. Further, as authorized by the
PSC, Central Hudson is currently permitted to defer, for future recovery from
customers, the differences between actual costs for MGP site investigation and
remediation and the associated rate allowances, with carrying charges to be
accrued on the deferred balances at the authorized pre-tax rate of return.
Eltings Corners
Central Hudson owns and operates a maintenance and warehouse facility. In the
course of Central Hudson's hazardous waste permit renewal process for this
facility, sediment contamination was discovered within the wetland area across
the street from the main property. In cooperation with the DEC, Central Hudson
continues to investigate the nature and extent of the contamination. The extent
of the contamination, as well as the timing and costs for any future remediation
efforts, cannot be reasonably estimated at this time and, accordingly, no amount
has been accrued in the interim unaudited consolidated financial statements.
Asbestos Litigation
Prior to the acquisition of CH Energy Group, various asbestos lawsuits had been
brought against Central Hudson. While a total of 3,341 asbestos cases have been
raised, 1,169 remained pending as at September 30, 2013. Of the cases no longer
pending against Central Hudson, 2,017 have been dismissed or discontinued
without payment by the Company, and Central Hudson has settled the remaining 155
cases. The Company is presently unable to assess the validity of the remaining
asbestos lawsuits; however, based on information known to Central Hudson at this
time, including the Company's experience in the settlement and/or dismissal of
asbestos cases, Central Hudson believes that the costs which may be incurred in
connection with the remaining lawsuits will not have a material effect on its
financial position, results of operations or cash flows and, accordingly, no
amount has been accrued in the interim unaudited consolidated financial
statements.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended December 31, 2011 through September 30, 2013. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements. These financial results are not necessarily
indicative of results for any future period and should not be relied upon to
predict future performance.
Summary of Quarterly Results
(Unaudited)
Net Earnings
Attributable to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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September 30, 2013 971 48 0.23 0.23
June 30, 2013 790 54 0.28 0.28
March 31, 2013 1,113 151 0.79 0.76
December 31, 2012 999 87 0.46 0.45
September 30, 2012 714 45 0.24 0.24
June 30, 2012 792 62 0.33 0.33
March 31, 2012 1,149 121 0.64 0.62
December 31, 2011 1,034 82 0.44 0.43
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The summary of the past eight quarters reflects the Corporation's continued
organic growth, growth from acquisitions, as well as the seasonality associated
with its businesses. Interim results will fluctuate due to the seasonal nature
of gas and electricity demand and water flows, as well as the timing and
recognition of regulatory decisions. Revenue is also affected by the cost of
fuel and purchased power and the commodity cost of natural gas, which are flowed
through to customers without markup. Given the diversified nature of the
Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of
the FortisBC Energy companies are realized in the first and fourth quarters.
September 2013/September 2012: Net earnings attributable to common equity
shareholders were $48 million, or $0.23 per common share, for the third quarter
of 2013 compared to earnings of $45 million, or $0.24 per common share, for the
third quarter of 2012. A discussion of the quarter over quarter variance in
financial results is provided in the "Financial Highlights" section of this
MD&A.
June 2013/June 2012: Net earnings attributable to common equity shareholders
were $54 million, or $0.28 per common share, for the second quarter of 2013
compared to earnings of $62 million, or $0.33 per common share, for the second
quarter of 2012. Earnings for the second quarter of 2013 were reduced by $32
million due to acquisition-related expenses and customer and community benefits
offered to obtain regulatory approval of the acquisition of CH Energy Group,
compared to $3 million of acquisition-related expenses in the second quarter of
2012. Earnings for the second quarter of 2013 were favourably impacted by an
income tax recovery of $25 million due to the enactment of higher deductions
associated with Part VI.1 tax on the Corporation's preference share dividends.
In the second quarter of 2012, earnings were reduced by income tax expenses of
$3 million associated with Part VI.1 tax. Excluding the above-noted
acquisition-related and Part VI.1 tax impacts, net earnings for the second
quarter of 2013 were $61 million compared to $68 million for the second quarter
of 2012. The decrease in earnings was mainly due to lower contribution from the
FortisBC Energy companies, FortisAlberta and FortisBC Electric, and decreased
non-regulated hydroelectric production in Belize due to lower rainfall,
partially offset by lower Corporate expenses. Earnings at the FortisBC Energy
companies and FortisBC Electric were reduced by $8 million and $2 million,
respectively, as a result of the regulatory decision related to the first phase
of the GCOC Proceeding in British Columbia, which was received in the second
quarter of 2013. At the FortisBC Energy companies, earnings contribution from
growth in energy infrastructure investment was largely offset by lower gas
transportation volumes and lower-than-expected customer additions.
FortisAlberta's earnings decreased due to lower net transmission revenue and
timing of the recognition of a regulatory decision in 2012 impacting
depreciation, partially offset by the timing of operating expenses, growth in
energy infrastructure investment and customer growth. At FortisBC Electric,
lower-than-expected finance charges, growth in energy infrastructure investment
and higher capitalized AFUDC favourably impacted earnings. Lower Corporate
expenses were primarily due to the favourable impact of the release of income
tax provisions in the second quarter of 2013, a higher foreign exchange gain and
lower finance charges, partially offset by higher preference share dividends.
March 2013/March 2012: Net earnings attributable to common equity shareholders
were $151 million, or $0.79 per common share, for the first quarter of 2013
compared to earnings of $121 million, or $0.64 per common share, for the first
quarter of 2012. Earnings for the first quarter of 2013 included an
extraordinary gain of approximately $22 million after tax upon the settlement of
expropriation matters associated with the Exploits Partnership. The remainder of
the increase in earnings was primarily due to higher contribution from
FortisAlberta, the FortisBC Energy companies and FortisBC Electric, and lower
Corporate expenses. Higher earnings at FortisAlberta were primarily due to lower
depreciation and net transmission revenue of approximately $2 million recognized
in the first quarter of 2013 associated with the finalization of 2012 net
transmission volume variances. At the FortisBC Energy companies, improved
performance was mainly due to rate base growth and increased gas transportation
volumes, partially offset by lower-than-expected customer additions and higher
effective income taxes. Increased earnings at FortisBC Electric due to rate base
growth, timing of operating expenses, lower-than-expected finance charges and
depreciation, and higher capitalized AFUDC were partially offset by higher
effective income taxes. Corporate expenses for the first quarter of 2013 were
reduced by $2 million related to foreign exchange, while Corporate expenses for
the first quarter of 2012 were increased by $1.5 million related to foreign
exchange. Acquisition-related expenses in the first quarter of 2013 were
approximately $0.5 million after tax compared to $4 million after tax in the
first quarter of 2012. Excluding foreign exchange impacts and
acquisition-related expenses noted above, Corporate expenses increased quarter
over quarter mainly due to higher preference share dividends, partially offset
by lower finance charges. The increase in earnings was partially offset by
decreased non-regulated hydroelectric production in Belize due to lower rainfall
and lower earnings at Maritime Electric and Fortis Properties.
December 2012/December 2011: Net earnings attributable to common equity
shareholders were $87 million, or $0.46 per common share, for the fourth quarter
of 2012 compared to earnings of $82 million, or $0.44 per common share, for the
fourth quarter of 2011. The increase in earnings was primarily due to higher
contribution from FortisAlberta, Other Canadian Regulated Electric Utilities and
FortisBC Electric, partially offset by decreased non-regulated hydroelectric
production in Belize associated with lower rainfall, increased Corporate
expenses and decreased earnings at the FortisBC Energy companies. Higher
earnings at FortisAlberta were driven by rate base growth, net transmission
revenue of $2 million recognized in the fourth quarter of 2012 and the rate
revenue reduction accrual during the fourth quarter of 2011, reflecting the
cumulative impact from January 1, 2011 of the decrease in the allowed ROE for
2011. At Other Canadian Regulated Electric Utilities, improved performance was
mainly due to lower effective income taxes at Maritime Electric and the accrual
of the cumulative return earned on FortisOntario's capital investment in smart
meters. Increased earnings at FortisBC Electric were driven by rate base growth,
lower-than-expected finance charges in 2012 and higher pole-attachment revenue,
partially offset by the expiry of the PBR mechanism on December 31, 2011. The
increase in Corporate expenses was largely due to a $3 million non-recurring
provision recognized in the fourth quarter of 2012 and lower effective income
tax recoveries, partially offset by a foreign exchange gain of $1 million
recognized in the fourth quarter of 2012, compared to a foreign exchange loss of
$1 million recognized in the fourth quarter of 2011, and lower finance charges.
At the FortisBC Energy companies, the decrease in earnings was mainly due to the
timing of certain operating and maintenance expenses during 2012, lower
capitalized AFUDC and lower-than-expected customer additions in 2012, partially
offset by rate base growth, higher gas transportation volumes and lower
effective income taxes.
OUTLOOK
Over the five years 2013 through 2017, the Corporation's consolidated capital
expenditure program is expected to total approximately $6 billion and will
support continuing growth in earnings and dividends. Capital investment over
that period is expected to allow utility rate base and hydroelectric generation
investment to increase at a combined compound annual growth rate of
approximately 6%.
With the closing of the acquisition of CH Energy Group in June 2013, the
Corporation's regulated midyear rate base has increased to more than $10
billion. The acquisition is expected to be accretive to earnings per common
share of Fortis beginning in 2015.
Fortis remains disciplined and patient in its pursuit of additional electric and
gas utility acquisitions in the United States and Canada that will add value for
its shareholders. Fortis will also pursue growth in its non-regulated businesses
in support of its regulated utility growth strategy.
SUBSEQUENT EVENT
In October 2013 the Corporation issued 10-year US$285 million unsecured notes at
3.84% and 30-year US$40 million unsecured notes at 5.08%. Proceeds from the
offering were used to repay a portion of the Corporation's US dollar-denominated
credit facility borrowings incurred to initially finance a portion of the CH
Energy Group acquisition and for general corporate purposes.
OUTSTANDING SHARE DATA
As at October 31, 2013, the Corporation had issued and outstanding approximately
212.4 million common shares; 8.0 million First Preference Shares, Series E; 5.0
million First Preference Shares, Series F; 9.2 million First Preference Shares,
Series G; 10.0 million First Preference Shares, Series H; 8.0 million First
Preference Shares, Series J; and 10.0 million First Preference Shares, Series K.
Only the common shares of the Corporation have voting rights. The Corporation's
First Preference Shares do not have voting rights unless and until Fortis fails
to pay eight quarterly dividends, whether or not consecutive and whether or not
such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding
stock options and First Preference Shares, Series E were converted as at October
31, 2013 is as follows.
----------------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at October 31, 2013
Number of
Common Shares
Security (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options 5.1
First Preference Shares, Series E 6.5
----------------------------------------------------------------------------
Total 11.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Additional information, including the Fortis 2012 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three and nine months ended September 30, 2013 and 2012 (Unaudited)
Prepared in accordance with accounting principles generally accepted in the
United States
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
September 30, December 31,
2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 25)
ASSETS
Current assets
Cash and cash equivalents $ 155 $ 154
Accounts receivable 523 587
Prepaid expenses 53 18
Inventories 172 133
Regulatory assets (Note 4) 146 185
Deferred income taxes 34 16
------------------------------
1,083 1,093
Other assets 233 200
Regulatory assets (Note 4) 1,825 1,515
Deferred income taxes 4 -
Utility capital assets 11,350 9,623
Non-utility capital assets 655 626
Intangible assets 356 325
Goodwill (Note 15) 2,064 1,568
------------------------------
$ 17,570 $ 14,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 20) $ 111 $ 136
Accounts payable and other current liabilities 847 966
Regulatory liabilities (Note 4) 108 72
Current installments of long-term debt 369 159
Current installments of capital lease and
finance obligations 7 7
Deferred income taxes 9 10
------------------------------
1,451 1,350
Other liabilities 808 638
Regulatory liabilities (Note 4) 804 681
Deferred income taxes 1,064 702
Long-term debt 6,750 5,741
Capital lease and finance obligations 421 428
------------------------------
11,298 9,540
------------------------------
Shareholders' equity
Common shares (1)(Note 5) 3,760 3,121
Preference shares (Note 6) 1,229 1,108
Additional paid-in capital 16 15
Accumulated other comprehensive loss (101) (96)
Retained earnings 1,013 952
------------------------------
5,917 5,100
Non-controlling interests (Note 7) 355 310
------------------------------
6,272 5,410
------------------------------
$ 17,570 $ 14,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) No par value. Unlimited authorized shares; 212.4 million and 191.6
million issued and outstanding as at September 30, 2013 and December
31, 2012, respectively
Commitments and Contingent Liabilities (Notes 21 and 23, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Nine Months Ended
2013 2012 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 971 $ 714 $ 2,874 $ 2,655
----------------------------------------------------------
Expenses
Energy supply
costs 356 235 1,143 1,092
Operating 299 203 726 621
Depreciation and
amortization 141 118 400 351
----------------------------------------------------------
796 556 2,269 2,064
----------------------------------------------------------
Operating income 175 158 605 591
Other income
(expenses), net
(Note 10) 2 1 (36) (2)
Finance charges
(Note 11) 103 93 284 276
----------------------------------------------------------
Earnings before
income taxes and
extraordinary
item 74 66 285 313
Income tax expense
(Note 12) 7 7 3 44
----------------------------------------------------------
Earnings before
extraordinary
item 67 59 282 269
Extraordinary
gain, net of tax
(Note 13) - - 22 -
----------------------------------------------------------
Net earnings $ 67 $ 59 $ 304 $ 269
----------------------------------------------------------
----------------------------------------------------------
Net earnings
attributable to:
Non-controlling
interests $ 3 $ 3 $ 7 $ 7
Preference
equity
shareholders 16 11 44 34
Common equity
shareholders 48 45 253 228
----------------------------------------------------------
$ 67 $ 59 $ 304 $ 269
----------------------------------------------------------
----------------------------------------------------------
Earnings per
common share
before
extraordinary
item (Note 14)
Basic $ 0.23 $ 0.24 $ 1.16 $ 1.20
Diluted $ 0.23 $ 0.24 $ 1.16 $ 1.19
Earnings per
common share
(Note 14)
Basic $ 0.23 $ 0.24 $ 1.27 $ 1.20
Diluted $ 0.23 $ 0.24 $ 1.27 $ 1.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
----------------------------------------------------------------------------
2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 67 $ 59 $ 304 $ 269
--------------------------------------------------
Other comprehensive loss
Unrealized foreign
currency translation
losses, net of hedging
activities and tax (15) (3) (7) (3)
Unrealized employee future
benefits gains, net of
tax - - 2 1
--------------------------------------------------
(15) (3) (5) (2)
--------------------------------------------------
Comprehensive income $ 52 $ 56 $ 299 $ 267
--------------------------------------------------
Comprehensive income
attributable to:
Non-controlling
interests $ 3 $ 3 $ 7 $ 7
Preference equity
shareholders 16 11 44 34
Common equity
shareholders 33 42 248 226
--------------------------------------------------
$ 52 $ 56 $ 299 $ 267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Quarter Ended Nine Months Ended
2013 2012 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 67 $ 59 $ 304 $ 269
Adjustments to reconcile
net earnings to net cash
provided by operating
activities:
Depreciation - capital
assets 123 105 351 316
Amortization -
intangible assets 13 12 36 33
Amortization - other 5 1 13 2
Deferred income tax
expense (recovery) 4 - (18) 8
Accrued employee future
benefits 12 3 14 (4)
Equity component of
allowance for funds
used during
construction (Note 10) (1) (1) (5) (4)
Other 9 1 (14) (10)
Change in long-term
regulatory assets and
liabilities (45) (16) (54) (25)
Change in non-cash
operating working capital
(Note 17) (85) 57 53 219
--------------------------------------------------
102 221 680 804
--------------------------------------------------
Investing activities
Change in other assets and
other liabilities (3) (2) (16) 2
Capital expenditures -
utility capital assets (243) (264) (750) (737)
Capital expenditures -
non-utility capital
assets (11) (9) (35) (24)
Capital expenditures -
intangible assets (8) (10) (24) (33)
Contributions in aid of
construction 16 15 46 45
Business acquisitions, net
of cash acquired (Note
15) - (7) (1,055) (14)
--------------------------------------------------
(249) (277) (1,834) (761)
--------------------------------------------------
Financing activities
Change in short-term
borrowings 23 17 (55) (61)
Proceeds from long-term
debt, net of issue costs 150 - 201 -
Repayments of long-term
debt and capital lease
and finance obligations (5) - (70) (57)
Net borrowings under
committed credit
facilities (187) (9) 511 221
Advances from non-
controlling interests 1 14 44 83
Subscription Receipts
issue costs (Note 5) - (1) - (13)
Issue of common shares,
net of costs and
dividends reinvested
(Note 5) 3 6 592 12
Issue of preference
shares, net of costs
(Note 6) 242 - 242 -
Redemption of preference
shares (Note 6) (125) - (125) -
Dividends
Common shares, net of
dividends reinvested (49) (42) (134) (128)
Preference shares (16) (11) (44) (34)
Subsidiary dividends
paid to non-controlling
interests (2) (2) (7) (6)
--------------------------------------------------
35 (28) 1,155 17
--------------------------------------------------
Change in cash and cash
equivalents (112) (84) 1 60
Cash and cash equivalents,
beginning of period 267 231 154 87
--------------------------------------------------
Cash and cash equivalents,
end of period $ 155 $ 147 $ 155 $ 147
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note 17)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended September 30
(in millions of Canadian dollars)
Accumulated
Additional Other
Common Preference Paid-in Comprehensive
Shares Shares Capital Loss
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 5) (Note 6)
As at January 1, 2013 $ 3,121 $ 1,108 $ 15 $ (96)
Net earnings - - - -
Other comprehensive loss - - - (5)
Preference share issue - 244 - -
Preference share redemption - (123) - -
Common share issues 639 - (1) -
Stock-based compensation - - 2 -
Advances from non-
controlling interests - - - -
Foreign currency
translation impacts - - - -
Subsidiary dividends paid
to non-controlling
interests - - - -
Dividends declared on
common shares ($0.93 per
share) - - - -
Dividends declared on
preference shares - - - -
-------------------------------------------------
As at September 30, 2013 $ 3,760 $ 1,229 $ 16 $ (101)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at January 1, 2012 $ 3,036 $ 912 $ 14 $ (95)
Net earnings - - - -
Other comprehensive loss - - - (2)
Common share issues 56 - (1) -
Stock-based compensation - - 2 -
Advances from non-
controlling interests - - - -
Foreign currency
translation impacts - - - -
Subsidiary dividends paid
to non-controlling
interests - - - -
Dividends declared on
common shares ($0.90 per
share) - - - -
Dividends declared on
preference shares - - - -
-------------------------------------------------
As at September 30, 2012 $ 3,092 $ 912 $ 15 $ (97)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-
Retained Controlling Total
Earnings Interests Equity
---------------------------------------------------------------
---------------------------------------------------------------
As at January 1, 2013 $ 952 $ 310 $ 5,410
Net earnings 297 7 304
Other comprehensive loss - - (5)
Preference share issue - - 244
Preference share redemption - - (123)
Common share issues - - 638
Stock-based compensation - - 2
Advances from non-
controlling interests - 44 44
Foreign currency
translation impacts - 1 1
Subsidiary dividends paid
to non-controlling
interests - (7) (7)
Dividends declared on
common shares ($0.93 per
share) (192) - (192)
Dividends declared on
preference shares (44) - (44)
------------------------------------
As at September 30, 2013 $ 1,013 $ 355 $ 6,272
---------------------------------------------------------------
---------------------------------------------------------------
As at January 1, 2012 $ 868 $ 208 $ 4,943
Net earnings 262 7 269
Other comprehensive loss - - (2)
Common share issues - - 55
Stock-based compensation - - 2
Advances from non-
controlling interests - 83 83
Foreign currency
translation impacts - (4) (4)
Subsidiary dividends paid
to non-controlling
interests - (6) (6)
Dividends declared on
common shares ($0.90 per
share) (173) - (173)
Dividends declared on
preference shares (34) - (34)
------------------------------------
As at September 30, 2012 $ 923 $ 288 $ 5,133
---------------------------------------------------------------
---------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2013 and 2012
(unless otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
NATURE OF OPERATIONS
Fortis Inc. ("Fortis" or the "Corporation") is principally an international gas
and electric distribution utility holding company. Fortis segments its utility
operations by franchise area and, depending on regulatory requirements, by the
nature of the assets. Fortis also holds investments in non-regulated generation
assets and non-utility assets, which are treated as two separate segments.
TheCorporation's reporting segments allow senior management to evaluate the
operational performance and assess the overall contribution of each segment to
the long-term objectives of Fortis. Each entity within the reporting segments
operates autonomously, assumes profit and loss responsibility and is accountable
for its own resource allocation.
The following outlines each of the Corporation's reportable segments and is
consistent with the basis of segmentation as disclosed in the Corporation's 2012
annual audited consolidated financial statements, with the exception of the
acquisition of CH Energy Group, Inc. ("CH Energy Group") on June 27, 2013 (Note
15).
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities are as follows:
a. Regulated Gas Utilities - Canadian: The FortisBC Energy companies,
comprised of FortisBC Energy Inc., FortisBC Energy (Vancouver Island)
Inc. ("FEVI") and FortisBC Energy (Whistler) Inc.
b. Regulated Gas & Electric Utility - United States: Central Hudson Gas &
Electric Corporation ("Central Hudson"), acquired by Fortis as part of
the acquisition of CH Energy Group (Note 15).
c. Regulated Electric Utilities - Canadian: Comprised of FortisAlberta,
FortisBC Electric, Newfoundland Power, and Other Canadian Electric
Utilities (Maritime Electric and FortisOntario). FortisOntario mainly
includes Canadian Niagara Power Inc., Cornwall Street Railway, Light and
Power Company, Limited and Algoma Power Inc.
d. Regulated Electric Utilities - Caribbean: Comprised of Caribbean
Utilities, in which Fortis holds an approximate 60% controlling
interest; and two wholly owned utilities in the Turks and Caicos
Islands, FortisTCI Limited ("FortisTCI") and Turks and Caicos Utilities
Limited, acquired in August 2012, (collectively "Fortis Turks and
Caicos"). In June 2013 Atlantic Equipment & Power
(Turks and Caicos) Ltd. was amalgamated with FortisTCI.
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation
assets in Belize, Ontario, British Columbia and Upstate New York. In March 2013
the Corporation and the Government of Newfoundland and Labrador settled all
matters, including release from all debt obligations, pertaining to the December
2008 expropriation of non-regulated hydroelectric generating assets and water
rights in central Newfoundland, then owned by the Exploits River Hydro
Partnership ("Exploits Partnership") in which Fortis held an indirect 51%
interest (Note 13).
NON-REGULATED - NON-UTILITY
a. Fortis Properties: Fortis Properties owns and operates 23 hotels,
comprised of more than 4,400 rooms, in eight Canadian provinces, and
owns and operates approximately 2.7 million square feet of commercial
office and retail space, primarily in Atlantic Canada.
b. Griffith: Comprised primarily of Griffith Energy Services, Inc.
("Griffith"), acquired by Fortis as part of the acquisition of CH Energy
Group (Note 15). Griffith mainly supplies petroleum products and related
services to approximately 65,000 customers in the Mid-Atlantic Region of
the United States.
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not
specifically related to any reportable segment and those business operations
that are below the required threshold for reporting as separate segments.
The Corporate and Other segment includes Fortis net corporate expenses and the
net expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related
activities. Also included in the Corporate and Other segment are the financial
results of CustomerWorks Limited Partnership ("CWLP") and FortisBC Alternative
Energy Services Inc. ("FAES"). CWLP is a non-regulated shared-services business
in which FHI holds a 30% interest. CWLP provides billing and customer care
services to utilities, municipalities and certain energy companies. CWLP's
financial results are recorded using the equity method of accounting. FAES is a
wholly owned subsidiary of FHI that provides alternative energy solutions,
including thermal-energy and geo-exchange systems.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance
with accounting principles generally accepted in the United States ("US GAAP")
for interim financial statements. As a result, these interim consolidated
financial statements do not include all of the information and disclosures
required in the annual consolidated financial statements and should be read in
conjunction with the Corporation's 2012 annual audited consolidated financial
statements. In management's opinion, the interim consolidated financial
statements include all adjustments that are of a recurring nature and necessary
to present fairly the consolidated financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of gas and electricity
demand and water flows, as well as the timing and recognition of regulatory
decisions. As a result of natural gas consumption patterns, most of the annual
earnings of the FortisBC Energy companies are realized in the first and fourth
quarters. Given the diversified group of companies, seasonality may vary.
The preparation of the consolidated financial statements in accordance with US
GAAP requires management to make estimates and judgments that affect the
reported amounts of assets and liabilities and the disclosure of contingent
assets and liabilities at the date of the consolidated financial statements and
the reported amounts of revenue and expenses during the reporting periods.
Estimates and judgments are based on historical experience, current conditions
and various other assumptions believed to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory
environments in which the Corporation's utilities operate often require amounts
to be recorded at estimated values until these amounts are finalized pursuant to
regulatory decisions or other regulatory proceedings. 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
recognized in earnings in the period in which they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the three and nine months
ended September 30, 2013.
An evaluation of subsequent events through to October 31, 2013, the date these
interim consolidated financial statements were approved by the Audit Committee
of the Board of Directors, was completed to determine whether circumstances
warranted recognition and disclosure of events or transactions in the interim
consolidated financial statements as at September 30, 2013 (Note 24).
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements are comprised of the accounts of
Fortis and its wholly owned subsidiaries and controlling ownership interests,
including the financial statements of CH Energy Group commencing June 27, 2013,
the date of acquisition. All significant intercompany balances and transactions
have been eliminated on consolidation.
These interim consolidated financial statements have been prepared following the
same accounting policies and methods as those used to prepare the Corporation's
2012 annual audited consolidated financial statements, except as described
below.
Regulation
Central Hudson is regulated by the New York State Public Service Commission
("PSC") regarding such matters as rates, construction, operations, financing and
accounting. Certain activities of the Company are subject to regulation by the
U.S. Federal Energy Regulatory Commission under the Federal Power Act (United
States). Central Hudson is also subject to regulation by the North American
Electric Reliability Corporation.
Central Hudson operates under cost of service ("COS") regulation as administered
by the PSC. The PSC uses a future test year to establish rates for the utility
and, pursuant to this method, the determination of the approved rate of return
on forecast rate base and deemed capital structure, together with the forecast
of all reasonable and prudent costs, establishes the revenue requirement upon
which the Company's customer rates are determined. Once rates are approved, they
are not adjusted as a result of actual COS being different from that which was
applied for, other than for certain prescribed costs that are eligible for
deferral account treatment.
Central Hudson's allowed rate of return on common shareholders' equity ("ROE")
is set at 10% on a deemed capital structure of 48% common equity. The Company
began operating under a three-year rate order issued by the PSC effective July
1, 2010. As approved by the PSC in June 2013, the original three-year rate order
has been extended for two years, through June 30, 2015, as a condition required
to close the acquisition (Note 15). Effective July 1, 2013, Central Hudson is
also subject to a modified earnings sharing mechanism, whereby the Company and
customers equally share earnings in excess of the allowed ROE up to an achieved
ROE that is 50 basis points above the allowed ROE, and share 10%/90%
(Company/customers) earnings in excess of 50 basis points above the allowed ROE.
Central Hudson's approved regulatory regime allows for full recovery of
purchased electricity and natural gas costs. The Company's rates also include
Revenue Decoupling Mechanisms ("RDMs"), which are intended to minimize the
earnings impact resulting from reduced energy consumption as energy-efficiency
programs are implemented. The RDMs allow the Company to recognize electric
delivery revenue and gas revenue at the levels approved in rates for most of
Central Hudson's customer base. Deferral account treatment is approved for
certain other specified costs, including provisions for manufactured gas plant
("MGP") site remediation, pension and other post employment benefit ("OPEB")
costs.
New Accounting Policies
Disclosures About Offsetting Assets and Liabilities
Effective January 1, 2013, the Corporation adopted the amendments to Accounting
Standards odification ("ASC") Topic 210, Balance Sheet - Disclosures About
Offsetting Assets and Liabilities as outlined in Accounting Standards Update
("ASU") No. 2011-11 and ASU No. 2013-01. The amendments improve the transparency
of the effect or potential effect of netting arrangements on a company's
financial position by expanding the level of disclosures required by entities
for such arrangements. The above-noted amendments were applied retrospectively
and did not materially impact the Corporation's interim consolidated financial
statements for the three and nine months ended September 30, 2013.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
Effective January 1, 2013, the Corporation adopted the amendments to ASC Topic
220, Other Comprehensive Income - Reporting of Amounts Reclassified Out of
Accumulated Other Comprehensive Income ("AOCI") as outlined in ASU No. 2013-02.
The amendments improve the reporting of reclassifications out of AOCI and
require entities to report, in one place, information about reclassifications
out of AOCI and to present details of the reclassifications in the disclosure
for changes in AOCI balances. The amendments were applied by the Corporation
prospectively commencing on January 1, 2013 and did not materially impact the
Corporation's interim consolidated financial statements for the three and nine
months ended September 30, 2013.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
Obligations Resulting from Joint and Several Liability Arrangements
In February 2013, the Financial Accounting Standards Board ("FASB") issued ASU
No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements
for Which the Total Amount of the Obligation is Fixed at the Reporting Date. The
objective of this update is to provide guidance for the recognition,
measurement, and disclosure of obligations resulting from joint and several
liability arrangements for which the total amount of the obligation is fixed at
the reporting date. This accounting update is effective for annual and interim
periods beginning on or after December 15, 2013 and is to be applied
retrospectively. Fortis does not expect that the adoption of this update will
have a material impact on its consolidated financial statements.
Parent's Accounting for the Cumulative Translation Adjustment
In March 2013, FASB issued ASU No. 2013-5, Parent's Accounting for the
Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or
Groups of Assets within a Foreign Entity or of an Investment in a Foreign
Entity. This update applies to the release of the cumulative translation
adjustment into net earnings when a parent either sells a part or all of its
investment in a foreign entity or no longer holds a controlling financial
interest in a subsidiary or group of assets within a foreign entity. This
accounting update is effective for annual and interim periods beginning on or
after December 15, 2013 and is to be applied prospectively. Fortis does not
expect that the adoption of this update will have a material impact on its
consolidated financial statements.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax
Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax
Credit Carryforward Exists. This amendment provides guidance on the presentation
of unrecognized tax benefits when net operating loss carryforwards, similar tax
losses, or tax credit carryforwards exist and is intended to better reflect the
manner in which an entity would settle any additional income taxes that would
result from the disallowance of a tax position when net operating loss
carryforwards, similar tax losses, or tax credit carryforwards exist. This
accounting update is effective for annual and interim periods beginning on or
after December 15, 2013 and is to be applied prospectively. Fortis does not
expect that the adoption of this update will have a material impact on its
consolidated financial statements.
4. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. For a detailed description of the nature of the Corporation's regulatory
assets and liabilities, refer to Note 7 to the Corporation's 2012 annual audited
consolidated financial statements.
As at
September 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes (i) 822 713
Employee future benefits (i) 637 498
Deferred lease costs - FortisBC Electric 81 77
Deferred energy management costs (i) 61 50
Rate stabilization accounts - electric
utilities (i) 56 57
Deferred operating overhead costs 40 32
Deferred net losses on disposal of utility
capital assets and intangible assets 34 27
Rate stabilization accounts - gas utilities
(i) 29 48
Income taxes recoverable on OPEB plans 23 23
Customer Care Enhancement Project cost
deferral 22 24
Alternative energy projects cost deferral 15 18
Whistler pipeline contribution deferral 13 14
MGP site remediation deferral (i) 12 -
Deferred development costs for capital
projects 10 10
Natural gas transportation incentive deferral 9 4
Residual natural gas deferral (i) 7 -
Deferred costs - smart meters 1 9
Replacement energy deferral - Point Lepreau
(ii) - 47
Other regulatory assets (i) 99 49
----------------------------------------------------------------------------
Total regulatory assets 1,971 1,700
Less: current portion (146) (185)
----------------------------------------------------------------------------
Long-term regulatory assets 1,825 1,515
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at
September 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Regulatory liabilities
Non-asset retirement obligation removal cost
provision (iii) 556 486
Rate stabilization accounts - gas utilities
(iii) 105 117
Rate stabilization accounts - electric
utilities (iii) 41 46
Alberta Electric System Operator charges
deferral 40 44
Deferred income taxes (iii) 31 12
OPEB cost deferral (iii) 27 -
Customer and community benefits obligation
(iii) 22 -
Meter reading and customer service variance
deferral 13 6
Rate base impact of tax repair project (iii) 10 -
Deferred interest 8 9
Income tax variance deferral 3 7
Other regulatory liabilities (iii) 56 26
----------------------------------------------------------------------------
Total regulatory liabilities 912 753
Less: current portion (108) (72)
----------------------------------------------------------------------------
Long-term regulatory liabilities 804 681
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Description of the Nature of Regulatory Assets and Liabilities
i. The respective regulatory assets as at September 30, 2013 include
amounts related to Central Hudson. MGP site remediation and residual
natural gas deferrals are being amortized and collected from customers
over a two- and four-year period, respectively, as approved by the
regulator.
ii. In March 2013 Maritime Electric received proceeds of approximately $47
million from the Government of Prince Edward Island upon its assumption
of the utility's replacement energy deferral during the refurbishment of
the New Brunswick Power Point Lepreau nuclear generating station ("Point
Lepreau").
iii.The respective regulatory liabilities as at September 30, 2013 include
amounts related to Central Hudson. As approved by the regulator, the
difference between Central Hudson's defined benefit pension and OPEB
costs recognized under US GAAP and those which are expected to be
refunded to, or recovered from, customers in future rates are subject to
deferral account treatment. As a result, a regulatory liability has been
recognized in relation to Central Hudson's OPEB plan.
As approved by the PSC, Fortis will provide Central Hudson's customers
and community with approximately US$50 million in financial benefits
that would not have been realized in the absence of the acquisition
(Note 15). These incremental benefits include: (i) US$35 million to
cover expenses that would normally be recovered in customer rates; (ii)
guaranteed savings to customers of more than US$9 million over five
years resulting from the elimination of costs CH Energy Group would
otherwise incur as a public company; and (iii) the establishment of a
US$5 million Community Benefit Fund to be used for low-income customer
and economic development programs for communities and residents of the
Mid-Hudson River Valley. As a result, $41 million (US$40 million) in
expenses were recognized in the second quarter of 2013 associated with
the write-off of a $20 million (US$20 million) regulatory asset related
to deferred storm costs and the recognition of a regulatory liability
for customer and community benefits of $21 million (US$20 million)
(Notes 10 and 15).
The tax repair project regulatory liability represents accumulated tax
refunds plus accrued carrying charges to be refunded to customers
through future rates over a time period to be determined during Central
Hudson's next rate hearing with the PSC.
5. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
September 30, 2013 September 30, 2013
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning
of period 211,717 3,739 191,566 3,121
Public offering -
Conversion of
Subscription
Receipts - - 18,500 567
Dividend
Reinvestment Plan 591 17 1,637 52
Consumer Share
Purchase Plan 10 - 27 1
Employee Share
Purchase Plan 76 3 293 10
Stock Option Plans 24 1 395 9
----------------------------------------------------------------------------
Balance, end of
period 212,418 3,760 212,418 3,760
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In June 2012, to finance a portion of the acquisition of CH Energy Group, the
Corporation sold 18.5 million Subscription Receipts at $32.50 each, for gross
proceeds of approximately $601 million. On June 27, 2013, upon closing of the
acquisition of CH Energy Group, each Subscription Receipt was exchanged, without
payment of additional consideration, for one common share of Fortis. Each
Subscription Receipt Holder also received a cash payment of $1.22 per
Subscription Receipt, which is an amount equal to the aggregate amount of
dividends declared per common share of Fortis for which record dates have
occurred since the issuance of the Subscription Receipts. The proceeds to the
Corporation upon conversion of the Subscription Receipts were approximately $567
million, net of after-tax expenses (Note 15).
6. PREFERENCE SHARES
In July 2013, the Corporation redeemed all of the issued and outstanding $125
million 5.45% First Preference Shares, Series C at a redemption price of
$25.1456 per share, being equal to $25.00 plus the amount of accrued and unpaid
dividends per share. Upon redemption, approximately $2 million of after-tax
issuance costs associated with First Preference Shares, Series C were recognized
in net earnings attributable to preference equity shareholders.
In July 2013, the Corporation issued 10 million Cumulative Redeemable Fixed Rate
Reset First Preference Shares, Series K ("First Preference Shares, Series K") at
a price of $25.00 per share for net after-tax proceeds of $244 million.
The First Preference Shares, Series K are entitled to receive fixed cumulative
preferential cash dividends as and when declared by the Board of Directors of
the Corporation at a rate of 4.0%, in an amount equal to $1.00 per share per
annum, for each year up to but excluding March 1, 2019. The dividends are
payable in equal quarterly installments on the first day of each quarter. For
each five-year period after that date, the holders of First Preference Shares,
Series K are entitled to receive reset fixed cumulative preferential cash
dividends. The reset annual dividends per share will be determined by
multiplying $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 reset date
plus 2.05%.
On each Series K Conversion Date, the holders of First Preference Shares, Series
K, have the option to convert any or all of their First Preference Shares,
Series K into an equal number of Cumulative edeemable Floating Rate First
Preference Shares, Series L ("First Preference Shares, Series L"). The holders
of the Corporation's First Preference Shares, Series L will be entitled to
receive floating rate cumulative preferential cash dividends in the amount per
share determined by multiplying the applicable floating quarterly dividend rate
by $25.00. The floating quarterly dividend rate will be equal to the sum of the
average yield expressed as a percentage per annum on three-month Government of
Canada Treasury Bills plus 2.05%.
On or after specified dates, the Corporation has the option to redeem for cash
all or any part of the outstanding First Preference Shares, Series K and First
Preference Shares, Series L at specified fixed prices per share plus all accrued
and unpaid dividends up to but excluding the dates fixed for redemption.
First Preference Shares, Series K and First Preference Shares, Series L do not
have fixed maturity dates and are not redeemable at the option of the holders.
7. NON-CONTROLLING INTERESTS
As at
September 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Waneta Expansion Limited Partnership ("Waneta
Partnership") 262 220
Caribbean Utilities 74 71
Mount Hayes Limited Partnership 12 12
Preference shares of Newfoundland Power 7 7
----------------------------------------------------------------------------
355 310
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. STOCK-BASED COMPENSATION PLANS
In January 2013, 8,497 Deferred Share Units ("DSUs") were granted to the
Corporation's Board of Directors, representing the first quarter equity
component of the Directors' annual compensation and, where opted, their first
quarter component of annual retainers in lieu of cash. Each DSU represents a
unit with an underlying value equivalent to the value of one common share of the
Corporation.
In March 2013, 66,978 Performance Share Units ("PSUs") were paid out to the
President and Chief Executive Officer ("CEO") of the Corporation at $33.59 per
PSU, for a total of approximately $2 million. The payout was made upon the
three-year maturation period in respect of the PSU grant made in March 2010 and
the President and CEO satisfying the payment requirements, as determined by the
Human Resources Committee of the Board of Directors of Fortis.
In March 2013 the Corporation granted 807,600 options to purchase common shares
under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted
average trading price immediately preceding the date of grant of $33.58. The
options granted under the 2012 Plan are exercisable for a period not to exceed
ten years from the date of grant, expire no later than three years after the
termination, death or retirement of the optionee and vest evenly over a
four-year period on each anniversary of the date of grant. Directors are not
eligible to receive grants of options under the 2012 Plan. The fair value of
each option granted was $3.91 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.78
Expected volatility (%) 21.4
Risk-free interest rate (%) 1.31
Weighted average expected life (years) 5.3
In March 2013 the Corporation's Board of Directors approved the 2013 PSU Plan,
effective January 1, 2013. The 2013 PSU Plan represents a component of the
long-term incentives awarded to senior management of the Corporation and its
subsidiaries, including the President and CEO of Fortis. Each PSU represents a
unit with an underlying value equivalent to the value of one common share of the
Corporation and is subject to a three-year vesting period, at which time a cash
payment may be made, as determined by the Human Resources Committee of the Board
of Directors. Each PSU is entitled to accrue notional common share dividends
equivalent to those declared by the Corporation's Board of Directors. In May
2013, 136,058 PSUs were granted to senior management of the Corporation and its
subsidiaries.
In April 2013, 8,553 DSUs were granted to the Corporation's Board of Directors,
representing the second quarter equity component of the Directors' annual
compensation and, where opted, their second quarter component of annual
retainers in lieu of cash.
In July 2013, 7,892 DSUs were granted to the Corporation's Board of Directors,
representing the third quarter equity component of the Directors' annual
compensation and, where opted, their third quarter component of annual retainers
in lieu of cash.
For the three and nine months ended September 30, 2013, stock-based compensation
expense of approximately $1 million and $5 million, respectively, was recognized
($2 million and $5 million for the three and nine months ended September 30,
2012, respectively).
9. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans and defined contribution pension plans, including
group registered retirement savings plans, for employees. The Corporation and
certain subsidiaries also offer OPEB plans for qualifying employees. The net
benefit cost of providing the defined benefit pension and OPEB plans is detailed
in the following tables.
Quarter Ended September 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 10 6 3 2
Interest costs 18 12 4 2
Expected return on plan
assets (21) (12) - -
Amortization of actuarial
losses 13 6 3 2
Amortization of past service
credits/plan amendments - - (2) -
Regulatory adjustments (3) (2) (2) -
----------------------------------------------------------------------------
Net benefit cost 17 10 6 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date September 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 26 20 7 5
Interest costs 41 35 10 8
Expected return on plan
assets (48) (37) - -
Amortization of actuarial
losses 27 19 6 4
Amortization of past service
credits/plan amendments - - (4) (2)
Amortization of transitional
obligation - 1 - 1
Regulatory adjustments (10) (8) (1) 1
----------------------------------------------------------------------------
Net benefit cost 36 30 18 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three and nine months ended September 30, 2013, the Corporation expensed
$5 million and $12 million, respectively ($3 million and $10 million for the
three and nine months ended September 30, 2012 respectively), related to defined
contribution pension plans.
10. OTHER INCOME (EXPENSES), NET
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Equity component of
allowance for funds used
during construction
("AFUDC") 1 1 5 4
Net foreign exchange (loss)
gain (Notes 20 and 22) (2) (3) 3 (3)
Interest income 3 2 5 4
Acquisition-related expenses
(Note 15) (1) - (9) (8)
Acquisition-related customer
and community benefits
(Notes 4 and 15) - - (41) -
Other 1 1 1 1
----------------------------------------------------------------------------
2 1 (36) (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCE CHARGES
Quarter Ended Year-to-Date
September 30 September 30
----------------------------------------------------------------------------
($ millions) 2013 2012 2013 2012
Interest:
Long-term debt and capital
lease and finance
obligations 106 95 294 282
Short-term borrowings 2 3 6 6
Debt component of AFUDC (5) (5) (16) (12)
----------------------------------------------------------------------------
103 93 284 276
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. INCOME TAXES
Income taxes differ from the amount that would be expected to be generated by
applying the enacted combined Canadian federal and provincial statutory income
tax rate to earnings before income taxes. The following is a reconciliation of
consolidated statutory income taxes to consolidated effective income taxes.
Quarter Ended Year-to-Date
September 30 September 30
($ millions, except as
noted) 2013 2012 2013 2012
----------------------------------------------------------------------------
Combined Canadian federal
and provincial statutory
income tax rate 29.0% 29.0% 29.0% 29.0%
----------------------------------------------------------------------------
Statutory income tax rate
applied to earnings before
income taxes and
extraordinary item 21 19 83 91
Difference between Canadian
statutory income tax rate
and rates applicable to
foreign subsidiaries (5) (3) (13) (10)
Difference in Canadian
provincial statutory income
tax rates applicable to
subsidiaries in different
Canadian jurisdictions - (1) (8) (9)
Items capitalized for
accounting purposes but
expensed for income tax
purposes (13) (11) (39) (39)
Difference between capital
cost allowance and amounts
claimed for accounting
purposes 6 3 4 7
Non-deductible expenses 1 2 3 5
Impacts associated with Part
VI.1 tax - (1) (23) 2
Release of income tax
reserves (2) - (7) (2)
Difference between employee
future benefits paid and
amounts expensed for
accounting purposes - - 1 1
Other (1) (1) 2 (2)
----------------------------------------------------------------------------
Income tax expense 7 7 3 44
----------------------------------------------------------------------------
Effective income tax rate 9.5% 10.6% 1.1% 14.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In June 2013 the Government of Canada enacted changes associated with Part VI.1
tax on the Corporation's preference share dividends. In accordance with US GAAP,
income taxes are required to be recognized based on enacted tax legislation. In
the second quarter of 2013, the Corporation recognized an approximate $25
million income tax recovery due to the enactment of higher deductions associated
with Part VI.1 tax.
In June 2013 a settlement was reached with Canada Revenue Agency ("CRA")
resulting in the release of income tax provisions of approximately $5 million
(Note 23).
As at September 30, 2013, the Corporation had non-capital and capital loss
carryforwards of approximately $108 million (December 31, 2012 - $73 million),
of which $17 million (December 31, 2012 - $13 million) has not been recognized
in the consolidated financial statements. The non-capital loss carryforwards
expire between 2013 and 2033.
13. EXTRAORDINARY GAIN, NET OF TAX
Effective March 2013 the Corporation and the Government of Newfoundland and
Labrador settled all matters, including release from all debt obligations,
pertaining to the December 2008 expropriation of non-regulated hydroelectric
generating assets and water rights in central Newfoundland, then owned by the
Exploits Partnership, in which Fortis held an indirect 51% interest. As a result
of the settlement an extraordinary gain of approximately $25 million ($22
million after tax) was recognized in the first quarter of 2013.
14. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding. Diluted EPS is calculated using the
treasury stock method for options and the "if-converted" method for convertible
securities.
Earnings to Common Shareholders
--------------------------------------------
Before After Weighted
Extraordinary Extraordinary Extraordinary Average
Quarter Ended Gain Gain Gain Shares
September 30, 2013 ($ millions) ($ millions) ($ millions) (millions)
----------------------------------------------------------------------------
Basic EPS 48 - 48 212.0
Effect of potential
dilutive securities:
Stock Options - - - 0.7
Preference Shares 3 - 3 6.5
----------------------------------------------------------------------------
51 - 51 219.2
Deduct anti-dilutive
impacts:
Preference Shares (3) - (3) (6.5)
----------------------------------------------------------------------------
Diluted EPS 48 - 48 212.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
September 30, 2012
----------------------------------------------------------------------------
Basic EPS 45 - 45 190.2
Effect of potential
dilutive securities:
Stock Options - - - 0.9
Preference Shares 4 - 4 10.3
----------------------------------------------------------------------------
49 - 49 201.4
Deduct anti-dilutive
impacts:
Preference Shares (4) - (4) (10.3)
----------------------------------------------------------------------------
Diluted EPS 45 - 45 191.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings Per Share
---------------------------------------------
Before After
Quarter Ended Extraordinary Extraordinary Extraordinary
September 30, 2013 Gain Gain Gain
------------------------------------------------------------------
Basic EPS $ 0.23 $ - $ 0.23
Effect of potential
dilutive securities:
Stock Options
Preference Shares
------------------------------------------------------------------
Deduct anti-dilutive
impacts:
Preference Shares
------------------------------------------------------------------
Diluted EPS $ 0.23 $ - $ 0.23
------------------------------------------------------------------
------------------------------------------------------------------
Quarter Ended
September 30, 2012
------------------------------------------------------------------
Basic EPS $ 0.24 $ - $ 0.24
Effect of potential
dilutive securities:
Stock Options
Preference Shares
------------------------------------------------------------------
Deduct anti-dilutive
impacts:
Preference Shares
------------------------------------------------------------------
Diluted EPS $ 0.24 $ - $ 0.24
------------------------------------------------------------------
------------------------------------------------------------------
Earnings to Common Shareholders
--------------------------------------------
Before After Weighted
Extraordinary Extraordinary Extraordinary Average
Year-to-Date Gain Gain Gain Shares
September 30, 2013 ($ millions) ($ millions) ($ millions) (millions)
----------------------------------------------------------------------------
Basic EPS 231 22 253 199.1
Effect of potential
dilutive securities:
Stock Options - - - 0.7
Preference Shares 11 - 11 8.8
----------------------------------------------------------------------------
242 22 264 208.6
Deduct anti-dilutive
impacts:
Preference Shares (11) - (11) (8.8)
----------------------------------------------------------------------------
Diluted EPS 231 22 253 199.8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
September 30, 2012
----------------------------------------------------------------------------
Basic EPS 228 - 228 189.6
Effect of potential
dilutive securities:
Stock Options - - - 0.9
Preference Shares 12 - 12 10.3
----------------------------------------------------------------------------
240 - 240 200.8
Deduct anti-dilutive
impacts:
Preference Shares (5) - (5) (3.9)
----------------------------------------------------------------------------
Diluted EPS 235 - 235 196.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings Per Share
---------------------------------------------
Before After
Year-to-Date Extraordinary Extraordinary Extraordinary
September 30, 2013 Gain Gain Gain
------------------------------------------------------------------
Basic EPS $ 1.16 $ 0.11 $ 1.27
Effect of potential
dilutive securities:
Stock Options
Preference Shares
------------------------------------------------------------------
Deduct anti-dilutive
impacts:
Preference Shares
------------------------------------------------------------------
Diluted EPS $ 1.16 $ 0.11 $ 1.27
------------------------------------------------------------------
------------------------------------------------------------------
Year-to-Date
September 30, 2012
------------------------------------------------------------------
Basic EPS $ 1.20 $ - $ 1.20
Effect of potential
dilutive securities:
Stock Options
Preference Shares
------------------------------------------------------------------
Deduct anti-dilutive
impacts:
Preference Shares
------------------------------------------------------------------
Diluted EPS $ 1.19 $ - $ 1.19
------------------------------------------------------------------
------------------------------------------------------------------
15. BUSINESS ACQUISITIONS
CH ENERGY GROUP
On June 27, 2013 Fortis acquired all of the outstanding common shares of CH
Energy Group for US$65.00 per common share in cash, for an aggregate purchase
price of approximately US$1.5 billion, including the assumption of US$518
million of debt on closing. The net cash purchase price of approximately $1,019
million (US$972 million) was financed through proceeds from the issuance of 18.5
million common shares of Fortis, pursuant to the conversion of Subscription
Receipts on the closing of the acquisition, for proceeds of approximately $567
million, net of after-tax expenses (Note 5), with the balance being initially
funded through drawings under the Corporation's $1 billion committed credit
facility.
CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New
York. Its main business, Central Hudson, is a regulated transmission and
distribution utility serving approximately 00,000 electric and 76,000 natural
gas customers in eight counties of New York State's Mid-Hudson River Valley.
Central Hudson accounts for approximately 93% of the total assets of CH Energy
Group and is subject to regulation by the PSC under a traditional COS model
(Note 2). The determination of revenue and earnings is based on a regulated rate
of return that is applied to historic values, which do not change with a change
of ownership. Therefore, in determining the fair value of assets and liabilities
of Central Hudson at the date of acquisition, fair value approximates book
value. No fair value adjustments were recorded for the net assets acquired
because all of the economic benefits and obligations associated with them beyond
regulated rates of return accrue to the customers.
Non-regulated net assets acquired relate mainly to Griffith, which is primarily
a fuel delivery business. Fair value approximates book value, with the exception
of intangible assets associated with Griffith's customer relationships.
The following table summarizes the preliminary allocation of the purchase
consideration to the assets and liabilities acquired as at June 27, 2013 based
on their fair values, using an exchange rate of US$1.00=CDN$1.0484. The amount
of the purchase price allocated to goodwill is entirely associated with the
regulated gas and electric operations of Central Hudson.
($ millions) Total
----------------------------------------------------------------------------
Purchase consideration 1,019
Fair value assigned to net assets:
Current assets 215
Long-term regulatory assets 235
Utility capital assets 1,283
Non-utility capital assets 11
Intangible assets 45
Other long-term assets 33
Current liabilities (133)
Assumed short-term borrowings (39)
Assumed long-term debt (including current portion) (543)
Long-term regulatory liabilities (123)
Other long-term liabilities (468)
----------------------------------------------------------------------------
516
Cash and cash equivalents 19
----------------------------------------------------------------------------
Fair value of net assets acquired 535
----------------------------------------------------------------------------
Goodwill 484
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The acquisition has been accounted for using the acquisition method, whereby
financial results of the business acquired have been consolidated in the
financial statements of Fortis commencing on June 27, 2013.
Acquisition-related expenses totalled approximately $9 million ($6 million after
tax) for the nine months ended September 30, 2013 and have been recognized in
other income (expenses), net on the consolidated statement of earnings (Note
10). In addition, approximately $41 million (US$40 million), or $26 million
(US$26 million) after tax, in customer and community benefits offered to obtain
regulatory approval of the acquisition were expensed in the second quarter of
2013, as approved by the PSC, and were also recognized in other income
(expenses), net on the consolidated statement of earnings (Notes 4 and 10).
Supplemental Pro Forma Data
The unaudited pro forma financial information below gives effect to the
acquisition of CH Energy Group as if the transaction had occurred at the
beginning of 2012. This pro forma data is presented for information purposes
only, and does not necessarily represent the results that would have occurred
had the acquisition taken place at the beginning of 2012, nor is it necessarily
indicative of the results that may be expected in future periods.
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Pro forma revenue 971 931 3,391 3,346
Pro forma net
earnings (1) 67 65 357 300
----------------------------------------------------------------------------
(1) Pro forma net earnings exclude all acquisition-related expenses
incurred by CH Energy Group and the Corporation, net of tax (Note 10).
A pro forma adjustment has been made to net earnings for the
respective periods presented to reflect the Corporation's after-tax
financing costs associated with the acquisition.
CITY OF KELOWNA'S ELECTRICAL UTILITY ASSETS
In March 2013 FortisBC Electric acquired the electrical utility assets of the
City of Kelowna (the "City") for approximately $55 million, which now allows
FortisBC Electric to directly serve some 15,000 customers formerly served by the
City. FortisBC Electric had provided the City with electricity under a wholesale
tariff and had operated and maintained the City's electrical utility assets
under contract since 2000.
The acquisition was approved by the British Columbia Utilities Commission
("BCUC") in March 2013 and allowed for approximately $38 million of the purchase
price to be included in FortisBC Electric's rate base. Based on this regulatory
decision, the book value of the assets acquired has been assigned as fair value
in the purchase price allocation. FortisBC Electric is regulated under COS and
the determination of revenue and earnings is based on a regulated rate of return
that is applied to historic values, which do not change with a change in
ownership. Therefore, in determining the fair value of assets at the date of
acquisition, fair value approximates book value. No fair value adjustments were
recorded for the assets acquired because all of the economic benefits and
obligations associated with them beyond regulated rates of return accrue to the
customers.
The following table summarizes the allocation of the purchase price to the
assets acquired as at the date of acquisition based on their fair values.
($ millions) Total
----------------------------------------------------------------------------
Purchase consideration 55
Fair value assigned to assets:
Utility capital assets 38
Long-term deferred income tax asset 3
----------------------------------------------------------------------------
Fair value of assets acquired 41
----------------------------------------------------------------------------
Goodwill 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The acquisition has been accounted for using the acquisition method, whereby
financial results of the business acquired have been consolidated in the
financial statements of Fortis commencing in March 2013.
16. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED UTILITIES
------------------------------------------------------------
Gas &
Gas Electric Electric
------------------------------------------------------------
Quarter Ended Fortis- Total
September 30, BC Fortis- New- Elec- Elec-
2013 Energy Central BC found- Other tric tric
Cana- Hudson Fortis Elec- land Cana- Cana- Carib-
($ millions) dian US Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 194 170 119 74 105 97 395 77
Energy supply
costs 64 62 - 19 54 65 138 47
Operating
expenses 70 72 39 19 19 11 88 10
Depreciation and
amortization 44 10 37 12 13 7 69 9
----------------------------------------------------------------------------
Operating income 16 26 43 24 19 14 100 11
Other income
(expenses), net 1 1 - - 1 - 1 1
Finance charges 35 8 18 10 9 5 42 4
Income tax
(recovery)
expense (5) 7 - 3 3 2 8 -
----------------------------------------------------------------------------
Net (loss)
earnings (13) 12 25 11 8 7 51 8
Non-controlling
interests 1 - - - - - - 2
Preference share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders (14) 12 25 11 8 7 51 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 476 227 235 - 67 529 146
Identifiable
assets 4,504 1,710 2,973 1,775 1,375 698 6,821 673
----------------------------------------------------------------------------
Total assets 5,417 2,186 3,200 2,010 1,375 765 7,350 819
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 50 28 77 25 25 12 139 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
September 30,
2012
($ millions)
----------------------------------------------------------------------------
Revenue 192 - 117 71 100 91 379 72
Energy supply
costs 61 - - 16 54 59 129 45
Operating
expenses 64 - 40 20 17 11 88 7
Depreciation and
amortization 40 - 34 12 11 7 64 8
----------------------------------------------------------------------------
Operating income 27 - 43 23 18 14 98 12
Other income
(expenses), net 1 - - 1 1 - 2 1
Finance charges 36 - 17 9 9 4 39 4
Income tax
(recovery)
expense (2) - - 2 1 3 6 -
----------------------------------------------------------------------------
Net (loss)
earnings (6) - 26 13 9 7 55 9
Non-controlling
interests - - - - - - - 3
Preference share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders (6) - 26 13 9 7 55 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 - 227 221 - 67 515 138
Identifiable
assets 4,472 - 2,651 1,686 1,289 705 6,331 735
----------------------------------------------------------------------------
Total assets 5,385 - 2,878 1,907 1,289 772 6,846 873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 66 - 104 19 22 13 158 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
-----------------------------
Quarter Ended
September 30,
2013 Inter-
Fortis Non- Corporate segment
($ millions) Generation Utility and Other eliminations Total
-------------------------------------------------------------------
Revenue 12 124 6 (7) 971
Energy supply
costs - 45 - - 356
Operating
expenses 2 56 2 (1) 299
Depreciation and
amortization 2 7 - - 141
-------------------------------------------------------------------
Operating income 8 16 4 (6) 175
Other income
(expenses), net - - (1) (1) 2
Finance charges - 8 13 (7) 103
Income tax
(recovery)
expense - 2 (5) - 7
-------------------------------------------------------------------
Net (loss)
earnings 8 6 (5) - 67
Non-controlling
interests - - - - 3
Preference share
dividends - - 16 - 16
-------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders 8 6 (21) - 48
-------------------------------------------------------------------
-------------------------------------------------------------------
Goodwill - - - - 2,064
Identifiable
assets 837 792 637 (468) 15,506
-------------------------------------------------------------------
Total assets 837 792 637 (468) 17,570
-------------------------------------------------------------------
-------------------------------------------------------------------
Gross capital
expenditures 22 12 - - 262
-------------------------------------------------------------------
-------------------------------------------------------------------
Quarter Ended
September 30,
2012
($ millions)
-------------------------------------------------------------------
Revenue 8 65 5 (7) 714
Energy supply
costs - - - - 235
Operating
expenses 2 42 2 (2) 203
Depreciation and
amortization 1 5 - - 118
-------------------------------------------------------------------
Operating income 5 18 3 (5) 158
Other income
(expenses), net - - (3) - 1
Finance charges - 6 13 (5) 93
Income tax
(recovery)
expense - 4 (1) - 7
-------------------------------------------------------------------
Net (loss)
earnings 5 8 (12) - 59
Non-controlling
interests - - - - 3
Preference share
dividends - - 11 - 11
-------------------------------------------------------------------
Net (loss)
earnings
attributable to
common equity
shareholders 5 8 (23) - 45
-------------------------------------------------------------------
-------------------------------------------------------------------
Goodwill - - - - 1,566
Identifiable
assets 686 623 498 (425) 12,920
-------------------------------------------------------------------
Total assets 686 623 498 (425) 14,486
-------------------------------------------------------------------
-------------------------------------------------------------------
Gross capital
expenditures 39 9 - - 283
-------------------------------------------------------------------
-------------------------------------------------------------------
REGULATED UTILITIES
-----------------------------------------------------------
Gas &
Gas Electric Electric
-----------------------------------------------------------
Year-to-Date Fortis- Total
September 30, BC Fortis- New- Elec- Elec-
2013 Energy Central BC found- Other tric tric
Cana- Hudson Fortis Elec- land Cana- Cana- Carib-
($ millions) dian US Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 932 170 354 230 434 280 1,298 213
Energy supply
costs 386 62 - 58 279 183 520 131
Operating
expenses 207 72 117 61 58 36 272 26
Depreciation and
amortization 136 10 109 37 38 21 205 26
----------------------------------------------------------------------------
Operating income 203 26 128 74 59 40 301 30
Other income
(expenses), net 2 1 2 1 2 - 5 2
Finance charges 106 8 53 29 27 15 124 11
Income tax
expense
(recovery) 21 7 1 9 (5) 3 8 -
----------------------------------------------------------------------------
Net earnings
(loss) before
extraordinary
item 78 12 76 37 39 22 174 21
Extraordinary
gain, net of tax - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss) 78 12 76 37 39 22 174 21
Non-controlling
interests 1 - - - - - - 6
Preference share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 77 12 76 37 39 22 174 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 476 227 235 - 67 529 146
Identifiable
assets 4,504 1,710 2,973 1,775 1,375 698 6,821 673
----------------------------------------------------------------------------
Total assets 5,417 2,186 3,200 2,010 1,375 765 7,350 819
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 142 28 306 58 63 40 467 35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
September 30,
2012
($ millions)
----------------------------------------------------------------------------
Revenue 1,004 - 335 225 422 264 1,246 202
Energy supply
costs 472 - - 54 274 168 496 124
Operating
expenses 197 - 116 62 54 35 267 24
Depreciation and
amortization 120 - 99 36 33 20 188 24
----------------------------------------------------------------------------
Operating income 215 - 120 73 61 41 295 30
Other income
(expenses), net 2 - 2 1 2 - 5 2
Finance charges 107 - 49 29 27 15 120 11
Income tax
expense
(recovery) 20 - - 7 8 7 22 -
----------------------------------------------------------------------------
Net earnings
(loss) 90 - 73 38 28 19 158 21
Non-controlling
interests 1 - - - - - - 6
Preference share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 89 - 73 38 28 19 158 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 - 227 221 - 67 515 138
Identifiable
assets 4,472 - 2,651 1,686 1,289 705 6,331 735
----------------------------------------------------------------------------
Total assets 5,385 - 2,878 1,907 1,289 772 6,846 873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 144 - 304 52 58 35 449 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------
Year-to-Date
September 30,
2013 Inter-
Fortis Non- Corporate segment
($ millions) Generation Utility and Other eliminations Total
---------------------------------------------------------------------
Revenue 24 242 19 (24) 2,874
Energy supply
costs - 45 - (1) 1,143
Operating
expenses 7 139 8 (5) 726
Depreciation and
amortization 4 18 1 - 400
---------------------------------------------------------------------
Operating income 13 40 10 (18) 605
Other income
(expenses), net - - (45) (1) (36)
Finance charges - 20 34 (19) 284
Income tax
expense
(recovery) - 5 (38) - 3
---------------------------------------------------------------------
Net earnings
(loss) before
extraordinary
item 13 15 (31) - 282
Extraordinary
gain, net of tax 22 - - - 22
---------------------------------------------------------------------
Net earnings
(loss) 35 15 (31) - 304
Non-controlling
interests - - - - 7
Preference share
dividends - - 44 - 44
---------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 35 15 (75) - 253
---------------------------------------------------------------------
---------------------------------------------------------------------
Goodwill - - - - 2,064
Identifiable
assets 837 792 637 (468) 15,506
---------------------------------------------------------------------
Total assets 837 792 637 (468) 17,570
---------------------------------------------------------------------
---------------------------------------------------------------------
Gross capital
expenditures 101 36 - - 809
---------------------------------------------------------------------
---------------------------------------------------------------------
Year-to-Date
September 30,
2012
($ millions)
---------------------------------------------------------------------
Revenue 26 181 18 (22) 2,655
Energy supply
costs 1 - - (1) 1,092
Operating
expenses 6 124 8 (5) 621
Depreciation and
amortization 3 15 1 - 351
---------------------------------------------------------------------
Operating income 16 42 9 (16) 591
Other income
(expenses), net 1 - (11) (1) (2)
Finance charges 1 18 36 (17) 276
Income tax
expense
(recovery) 1 7 (6) - 44
---------------------------------------------------------------------
Net earnings
(loss) 15 17 (32) - 269
Non-controlling
interests - - - - 7
Preference share
dividends - - 34 - 34
---------------------------------------------------------------------
Net earnings
(loss)
attributable to
common equity
shareholders 15 17 (66) - 228
---------------------------------------------------------------------
---------------------------------------------------------------------
Goodwill - - - - 1,566
Identifiable
assets 686 623 498 (425) 12,920
---------------------------------------------------------------------
Total assets 686 623 498 (425) 14,486
---------------------------------------------------------------------
---------------------------------------------------------------------
Gross capital
expenditures 144 24 - - 794
---------------------------------------------------------------------
---------------------------------------------------------------------
Related party transactions are in the normal course of operations and are
measured at the exchange amount, which is the amount of consideration
established and agreed to by the related parties. The significant related party
inter-segment transactions primarily related to: (i) electricity sales from
Newfoundland Power to Non-Utility; and (ii) finance charges on related party
borrowings. The significant related party inter-segment transactions for the
three and nine months ended September 30, 2013 and 2012 were as follows:
Significant Inter-Segment Transactions Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Sales from Fortis Generation to
Other Canadian Electric Utilities - - 1 -
Sales from Newfoundland Power to Non-Utility 1 1 4 4
Inter-segment finance charges on lending
from:
Fortis Generation to Other Canadian
Electric Utilities - - - 1
Corporate to Regulated Electric Utilities
- Caribbean 1 1 3 3
Corporate to Fortis Generation - - - 1
Corporate to Non-Utility 4 4 14 12
----------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at
September 30
($ millions) 2013 2012
----------------------------------------------------------------------------
Inter-segment lending from:
Fortis Generation to Other Canadian
Electric Utilities 20 20
Corporate to Regulated Electric Utilities
- Caribbean 83 84
Corporate to Fortis Generation 13 12
Corporate to Non-Utility 325 284
Other inter-segment assets 27 25
----------------------------------------------------------------------------
Total inter-segment eliminations 468 425
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-Date
September 30 September 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Change in non-cash operating working
capital:
Accounts receivable 64 96 190 224
Prepaid expenses (20) (8) (18) (14)
Inventories (35) (48) (17) (21)
Regulatory assets - current portion 29 2 69 50
Accounts payable and other current
liabilities (112) 28 (185) (39)
Regulatory liabilities - current portion (11) (13) 14 19
----------------------------------------------------------------------------
(85) 57 53 219
--------------------------------
--------------------------------
Non-cash investing and financing activities:
Common share dividends reinvested 17 15 51 43
Additions to utility and non-utility capital
assets,
and intangible assets included in current
liabilities 84 73 84 73
Contributions in aid of construction
included in current assets 13 11 13 11
Exercise of stock options into common shares - - 1 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
18. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation generally limits the use of derivative instruments to those that
qualify as accounting or economic hedges. As at September 30, 2013, the
Corporation's derivative contracts consisted of fuel option contracts,
electricity swap contracts, natural gas swap and option contracts, and gas
purchase contract premiums. The fuel option contracts are held by Caribbean
Utilities. Electricity swap contracts are held by Central Hudson. Gas swaps and
options, and gas purchase contract premiums are held by the FortisBC Energy
companies and Central Hudson.
Volume of Derivative Activity
As at September 30, 2013, the following notional volumes related to fuel option
contracts and electricity and natural gas commodity derivatives that are
expected to be settled are outlined below.
2013 2014 2015 2016 2017
----------------------------------------------------------------------------
Fuel option contracts (millions of
imperial gallons) 1 - - - -
Electricity swap contracts (gigawatt
hours) 221 1,095 876 439 219
Gas swaps and options (petajoules) 3 7 - - -
Gas purchase contract premiums
(petajoules) 29 48 6 - -
----------------------------------------------------------------------------
Presentation of Derivative Instruments in the Consolidated Financial Statements
On the Corporation's consolidated balance sheets, derivative instruments are
presented on a net basis by counterparty, where the right of offset exists.
The Corporation's outstanding derivative balances are as follows:
As at
September 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Gross derivative balances (1) 22 60
Netting (2) - -
Cash collateral - -
----------------------------------------------------------------------------
Total derivative balances (3) 22 60
-----------------------------
-----------------------------
(1) Refer to Note 19 for a discussion of the valuation techniques used to
calculate the fair value of the derivative instruments.
(2) Positions, by counterparty, are netted where the intent and legal right
to offset exists.
(3) Unrealized losses on commodity risk-related derivative instruments as at
September 30, 2013 of $18 million were recognized in current regulatory
assets (December 31, 2012 - $60 million) and $4 million were recognized
in current regulatory liabilities. These unrealized losses would
otherwise be recognized on the consolidated statement of comprehensive
income and in accumulated other comprehensive loss.
Cash flows associated with the settlement of all derivative instruments are
included in operating cash flows on the Corporation's consolidated statements of
cash flows.
19. FAIR VALUE MEASUREMENTS
Fair value is the price at which a market participant could sell an asset or
transfer a liability to an unrelated party. A fair value measurement is required
to reflect the assumptions that market participants would use in pricing an
asset or liability based on the best available information. These assumptions
include the risks inherent in a particular valuation technique, such as a
pricing model, and the risks inherent in the inputs to the model. A fair value
hierarchy exists that prioritizes the inputs used to measure fair value. The
Corporation is required to record all derivative instruments at fair value
except for those which qualify for the normal purchase and normal sale
exception.
The three levels of the fair value hierarchy are defined as follows:
Level 1: Fair value determined using unadjusted quoted prices in active
markets;
Level 2: Fair value determined using pricing inputs that are observable; and
Level 3: Fair value determined using unobservable inputs only when relevant
observable inputs are not available.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
The following table details the estimated fair value measurements of the
Corporation's financial instruments, all of which were measured using Level 2
pricing inputs, except for other investments and certain long-term debt and
derivative instruments as noted below.
As at
Asset (Liability) September 30, 2013 December 31, 2012
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
Long-term other asset - Belize
Electricity (1) 105 n/a(2) 104 n/a (2)
Other investments (1) (3) 8 8 - -
Long-term debt, including
current portion (4) (7,119) (8,029) (5,900) (7,338)
Waneta Partnership promissory
note (5) (49) (50) (47) (51)
Fuel option contracts (6) - - (1) (1)
Electricity swap contracts (6) 1 1 - -
Natural gas commodity
derivatives: (6)
Gas swaps and options (23) (23) (51) (51)
Gas purchase contract premiums - - (8) (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in long-term other assets on the consolidated balance sheet
(2) The Corporation's expropriated investment in Belize Electricity is
recognized at book value, including foreign exchange impacts. The actual
amount of compensation that the Government of Belize may pay to Fortis
is indeterminable at this time (Notes 20 and 22).
(3) Other investments were valued using Level 1 inputs.
(4) The Corporation's $200 million unsecured debentures due 2039 and
consolidated borrowings under credit facilities classified as long-term
debt of $632 million (December 31, 2012 - $150 million) are valued using
Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
(5) Included in long-term other liabilities on the consolidated balance
sheet
(6) The fair values of the derivatives were recorded in accounts payable and
other current liabilities as at September 30, 2013 and December 31,
2012. The fair value of the fuel option contracts as at September 30,
2013 was less than $1 million. The fair value of electricity swap
contracts was determined using Level 3 inputs.
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, as is the case with the
Waneta Partnership promissory note and certain long-term debt, the fair value is
determined by either: (i) discounting the future cash flows of the specific debt
instrument at an estimated yield to maturity equivalent to benchmark government
bonds or treasury bills, with similar terms to maturity, plus a credit risk
premium equal to that of issuers of similar credit quality; or (ii) by obtaining
from third parties indicative prices for the same or similarly rated issues of
debt of the same remaining maturities. Since the Corporation does not intend to
settle the long-term debt or promissory note prior to maturity, the excess of
the estimated fair value above the carrying value does not represent an actual
liability.
The fuel option contracts are used by Caribbean Utilities to reduce the impact
of volatility in fuel prices on customer rates, as approved by the regulator
under the Company's Fuel Price Volatility Management Program. The fair value of
the fuel option contracts reflects only the value of the heating oil derivative
and not the offsetting change in the value of the underlying future purchases of
heating oil and was calculated using published market prices for heating oil or
similar commodities where appropriate. The fuel option contracts matured in
October 2013. Approximately 30% of the Company's annual diesel fuel requirements
are under fuel hedging arrangements.
The electricity swap contracts and natural gas commodity derivatives are used by
Central Hudson to minimize commodity price volatility for electricity and
natural gas purchases for the Company's full-service customers by fixing the
effective purchase price for the defined commodities. The fair values of the
electricity swap contracts and natural gas commodity derivatives were calculated
using forward pricing provided by independent third parties.
The natural gas commodity derivatives are used by the FortisBC Energy companies
to fix the effective purchase price of natural gas, as the majority of the
natural gas supply contracts have floating, rather than fixed, prices. The fair
value of the natural gas commodity derivatives was calculated using the present
value of cash flows based on market prices and forward curves for the commodity
cost of natural gas.
The fair values of the fuel option contracts, electricity swap contracts, and
natural gas commodity derivatives are estimates of the amounts that the
utilities would receive or have to pay to terminate the outstanding contracts as
at the balance sheet dates. As at September 30, 2013, none of the fuel option
contracts, electricity swap contracts and natural gas commodity derivatives were
designated as hedges of fuel purchases or electricity and natural gas supply
contracts. However, any gains or losses associated with changes in the fair
value of the derivatives were deferred as a regulatory asset or liability for
recovery from, or refund to, customers in future rates, as permitted by the
regulators.
20. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit Risk Risk that a counterparty to a financial instrument might fail
to meet its obligations under the terms of the financial
instrument.
Liquidity Risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market Risk Risk that the fair value or future cash flows of a financial
instrument will fluctuate due to changes in market prices.
The Corporation is exposed to foreign exchange risk, interest
rate risk and commodity price risk.
Credit Risk
For cash equivalents, trade and other accounts receivable, and long-term other
receivables, the Corporation's credit risk is generally limited to the carrying
value on the consolidated balance sheet. The Corporation generally has a large
and diversified customer base, which minimizes the concentration of credit risk.
The Corporation and its subsidiaries have various policies to minimize credit
risk, which include requiring customer deposits, prepayments and/or credit
checks for certain customers and performing disconnections and/or using
third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution
service billings being to a relatively small group of retailers. As at September
30, 2013, FortisAlberta's gross credit risk exposure was approximately $105
million, representing the projected value of retailer billings over a 37-day
period. The Company has reduced its exposure to less than $1 million by
obtaining from the retailers either a cash deposit, bond, letter of credit or an
investment-grade credit rating from a major rating agency, or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The FortisBC Energy companies may be exposed to credit risk in the event of
non-performance by counterparties to derivative instruments. The Company uses
netting arrangements to reduce credit risk and net settles payments with
counterparties where net settlement provisions exist. The following table
summarizes the FortisBC Energy companies' net credit risk exposure to its
counterparties, as well as credit risk exposure to counterparties accounting for
greater than 10% net credit exposure, as it relates to its natural gas swaps and
options.
As at
September 30, December 31,
($ millions, except as noted) 2013 2012
----------------------------------------------------------------------------
Gross credit exposure before credit collateral
(1) 23 51
Credit collateral - -
----------------------------------------------------------------------------
Net credit exposure (2) 23 51
----------------------------------------------------------------------------
Number of counterparties greater than 10% (#) 3 4
Net exposure to counterparties greater than
10% 19 45
----------------------------------------------------------------------------
(1) Gross credit exposure equals mark-to-market value on physically and
financially settled contracts, notes receivable and net receivables
(payables) where netting is contractually allowed. Gross and net credit
exposure amounts reported do not include adjustments for time value or
liquidity.
(2) Net credit exposure is the gross credit exposure collateral minus credit
collateral (cash deposits and letters of credit).
The Corporation is exposed to credit risk associated with the amount and timing
of fair value compensation that Fortis is entitled to receive from the
Government of Belize ("GOB") as a result of the expropriation of the
Corporation's investment in Belize Electricity by the GOB on June 20, 2011. As
at September 30, 2013, the Corporation had a long-term other asset of $105
million (December 31, 2012 - $104 million), including foreign exchange impacts,
recognized on the consolidated balance sheet related to its expropriated
investment in Belize Electricity (Notes 19 and 22).
Additionally, as at September 30, 2013, Belize Electricity owed Belize Electric
Company Limited ("BECOL") approximately US$8 million for energy purchases of
which US$3 million was overdue (December 31, 2012 - US$8 million, of which US$7
million was overdue). In accordance with long-standing agreements, the GOB
guarantees the payment of Belize Electricity's obligations to BECOL.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if
it, or one of its subsidiaries, fails to arrange sufficient and cost-effective
financing to fund, among other things, capital expenditures and the repayment of
maturing debt. The ability to arrange sufficient and cost-effective financing is
subject to numerous factors, including the consolidated results of operations
and financial position of the Corporation and its subsidiaries, conditions in
capital and bank credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed corporate credit facility is available for interim
financing of acquisitions and for general corporate purposes. Depending on the
timing of cash payments from the subsidiaries, borrowings under the
Corporation's committed corporate credit facility may be required from time to
time to support the servicing of debt and payment of dividends. As at September
30, 2013, average annual consolidated long-term debt maturities and repayments
over the next five years are expected to be approximately $335 million,
excluding borrowings under the Corporation's committed credit facility which
were subsequently replaced with long-term financing (Note 24). The combination
of available credit facilities and relatively low annual debt maturities and
repayments provide the Corporation and its subsidiaries with flexibility in the
timing of access to capital markets.
As at September 30, 2013, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.7 billion, of which $1.9 billion was
unused, including $490 million unused under the Corporation's $1 billion
committed revolving corporate credit facility. The credit facilities are
syndicated mostly with the seven largest Canadian banks, with no one bank
holding more than 20% of these facilities. Approximately $2.6 billion of the
total credit facilities are committed facilities with maturities ranging from
2014 to 2018.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
Regulated Non- Corporate September 30, December 31,
($ millions) Utilities Regulated and Other 2013 2012
----------------------------------------------------------------------------
Total credit
facilities 1,539 115 1,030 2,684 2,460
Credit
facilities
utilized:
Short-term
borrowings
(1) (111) - - (111) (136)
Long-term
debt (2) (123) - (509) (632) (150)
Letters of
credit
outstanding (65) - (1) (66) (67)
----------------------------------------------------------------------------
Credit
facilities
unused 1,240 115 520 1,875 2,107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The weighted average interest rate on short-term borrowings was
approximately 1.5% as at September 30, 2013 (December 31, 2012 - 1.9%).
(2) As at September 30, 2013, credit facility borrowings classified as long
term included $50 million in current installments of long-term debt on
the consolidated balance sheet (December 31, 2012 - $62 million). The
weighted average interest rate on credit facility borrowings classified
as long-term debt was approximately 2.9% as at September 30, 2013
(December 31, 2012 - 2.1%).
As at September 30, 2013 and December 31, 2012, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In January 2013 FEVI's $20 million unsecured committed non-revolving credit
facility matured and was not replaced.
In April 2013 FortisBC Electric renegotiated and amended its credit facility
agreement, resulting in an extension to the maturity of the Company's $150
million unsecured committed revolving credit facility with $100 million now
maturing in May 2016 and $50 million now maturing in May 2014. The amended
credit facility agreement contains substantially similar terms and conditions as
the previous credit facility agreement.
In April 2013 FHI extended its $30 million unsecured committed revolving credit
facility to mature in May 2014 from May 2013.
In May 2013 FortisOntario extended its $30 million unsecured revolving credit
facility to mature in June 2014 from June 2013.
In June 2013 Fortis Turks and Caicos entered into new short-term unsecured
demand credit facilities for US$21 million ($22 million), replacing its previous
US$21 million ($22 million) facilities. The new facilities are comprised of a
revolving operating credit facility of US$12 million ($12 million) and a US$9
million ($9 million) emergency standby loan. The facilities mature in June 2014,
with an option to renew annually. The new credit facilities reflect a decrease
in pricing but otherwise contain terms and conditions substantially similar to
the previous facilities.
In July 2013 FEI, FEVI and FortisAlberta amended their $500 million, $200
million and $250 million committed revolving credit facilities, resulting in
extensions to the maturity dates to August 2015, December 2015 and August 2018,
respectively, from August 2014, December 2013 and August 2016, respectively. The
new agreements contain substantially similar terms and conditions as the
previous credit facility agreements.
In August 2013 the Corporation extended its $1 billion committed revolving
corporate credit facility to mature in July 2018 from July 2015.
As at September 30, 2013, CH Energy Group had a US$100 million ($103 million)
unsecured revolving credit facility maturing in October 2015, and Central Hudson
had a US$150 million ($155 million) unsecured committed revolving credit
facility maturing in October 2016.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
September 30, 2013, the Corporation's credit ratings were as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt
credit rating)
DBRS A(low) (unsecured debt credit rating)
In February 2013 S&P and DBRS affirmed the Corporation's debt credit ratings.
The above-noted credit ratings reflect the Corporation's business-risk profile
and diversity of its operations, the stand-alone nature and financial separation
of each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis. The credit ratings also reflect the Corporation's financing
of the acquisition of CH Energy Group and the expected completion of the Waneta
Expansion hydroelectric generating facility on time and on budget.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investments in, foreign subsidiaries
are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate.
The Corporation has effectively decreased the above-noted exposure through the
use of US dollar-denominated borrowings at the corporate level. The foreign
exchange gain or loss on the translation of US dollar-denominated interest
expense partially offsets the foreign exchange loss or gain on the translation
of the Corporation's foreign subsidiaries' earnings, which are denominated in US
dollars. The reporting currency of Central Hudson, Caribbean Utilities, Fortis
Turks and Caicos, FortisUS Energy Corporation, BECOL and Griffith is the US
dollar.
As at September 30, 2013, the Corporation's corporately issued US$1,044 million
(December 31, 2012 - US$557 million) long-term debt had been designated as an
effective hedge of the Corporation's foreign net investments. As at September
30, 2013, the Corporation had approximately US$549 million (December 31, 2012 -
US$17 million) in foreign net investments remaining to be hedged. Both the
Corporation's US dollar-denominated long-term debt and foreign net investments
as at September 30, 2013 were significantly impacted by the CH Energy Group
acquisition. Foreign currency exchange rate fluctuations associated with the
translation of the Corporation's corporately issued US dollar-denominated
borrowings designated as effective hedges are recorded in other comprehensive
income and serve to help offset unrealized foreign currency exchange gains and
losses on the net investments in foreign subsidiaries, which gains and losses
are also recorded in other comprehensive income.
Effective from June 20, 2011, the Corporation's asset associated with its
expropriated investment in Belize Electricity does not qualify for hedge
accounting as Belize Electricity is no longer a foreign subsidiary of Fortis
(Note 22). As a result, foreign exchange gains and losses on the translation of
the long-term other asset associated with Belize Electricity are recognized in
earnings. The Corporation recognized in earnings a foreign exchange loss of $2
million for the three months ended and a foreign exchange gain of $3 million for
the nine months ended September 30, 2013 ($3 million foreign exchange loss for
the three and nine months ended September 30, 2012) (Note 10).
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk
associated with credit facility borrowings. The Corporation and its subsidiaries
may enter into interest rate swap agreements to help reduce this risk.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price risk associated
with changes in the market price of natural gas; Central Hudson is exposed to
commodity price risk associated with changes in the market price of electricity
and natural gas; and Caribbean Utilities is exposed to commodity price risk
associated with changes in the market price for fuel (Notes 18 and 19). The
risks have been reduced by entering into natural gas commodity derivatives,
electricity derivatives and fuel option contracts that effectively fix the price
of natural gas purchases, electricity purchases and fuel purchases,
respectively. The natural gas and electricity derivatives and fuel option
contracts are recorded on the consolidated balance sheet at fair value and any
change in the fair value is deferred as a regulatory asset or liability, as
permitted by the regulators, for recovery from, or refund to, customers in
future rates.
The price risk-management strategy of the FortisBC Energy companies aims to
improve the likelihood that natural gas prices remain competitive, mitigate gas
price volatility on customer rates and reduce the risk of regional price
discrepancies. As directed by the regulator in 2011, the FortisBC Energy
companies have suspended their commodity hedging activities with the exception
of certain limited swaps as permitted by the regulator. The existing hedging
contracts will continue in effect through to their maturity and the FortisBC
Energy companies' ability to fully recover the commodity cost of gas in customer
rates remains unchanged. Any differences between the cost of natural gas
purchased and the price of natural gas included in customer rates are recorded
as regulatory deferrals and are recovered from, or refunded to, customers in
future rates, subject to regulatory approval.
21. COMMITMENTS
There were no material changes in the nature and amount of the Corporation's
commitments from the commitments disclosed in the Corporation's 2012 annual
audited consolidated financial statements, except as follows.
Maritime Electric has entitlement to approximately 4.7% of the output from Point
Lepreau for the life of the unit. As part of its entitlement, Maritime Electric
is required to pay its share of the capital and operating costs of the unit. A
major refurbishment of Point Lepreau that began in 2008 was completed and the
station returned to service in November 2012. The refurbishment is expected to
extend the facility's estimated life an additional 27 years and, as a result,
the total estimated capital cost obligation has increased approximately $96
million from that disclosed in the 2012 annual audited consolidated financial
statements.
In May 2013 FortisBC Electric entered into a new Power Purchase Agreement
("PPA") with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of
associated energy annually for a 20-year term beginning October 1, 2013. This
new PPA does not change the basic parameters of the BC Hydro PPA, which expired
on September 30, 2013. An executed version of the PPA was submitted by BC Hydro
to the BCUC in May 2013 and is pending regulatory approval. In the interim
period until the new PPA is approved by the BCUC, FortisBC Electric and BC Hydro
have agreed to continue under the terms of the expired BC Hydro PPA. Power
purchases in the interim are approved for recovery in customer rates. The power
purchases from the new PPA are expected to be recovered in customer rates.
Central Hudson is party to various gas purchase contracts with obligations
totaling approximately $126 million as at September 30, 2013. These obligations
are based on tariff rates as at September 30, 2013.
Central Hudson is also party to agreements with Entergy Nuclear Power Marketing,
LLC to purchase electricity, and not capacity, on a unit-contingent basis at
defined prices from January 1, 2011 through December 31, 2013. Central Hudson
must also acquire sufficient peak load capacity to meet the peak load
requirements of its full-service customers. This capacity requirement is met
through contracts with capacity providers, purchases from the New York
Independent System Operator capacity market and the Company's own generating
capacity. Obligations in respect of electricity purchase agreements totalled $42
million as at September 30, 2013.
Central Hudson has various purchase commitments and contracts related to ongoing
projects and operating activities with an obligation totalling approximately
$119 million as at September 30, 2013.
22. EXPROPRIATED ASSETS
On June 20, 2011, the GOB enacted legislation leading to the expropriation of
the Corporation's investment in Belize Electricity. Consequent to the
deprivation of control over the operations of the utility, the Corporation
discontinued the consolidation method of accounting for Belize Electricity, as
of June 20, 2011, and classified the book value, including foreign exchange
impacts, of the expropriated investment as a long-term other asset on the
consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with
respect to challenging the constitutionality of the expropriation of the
Corporation's investment in Belize Electricity. Fortis commissioned an
independent valuation of its expropriated investment and submitted its claim for
compensation to the GOB in November 2011. The book value of the long-term other
asset is below fair value as at the date of expropriation as determined by
independent valuators. The GOB also commissioned a valuation of Belize
Electricity which is significantly lower than both the fair value determined
under the Corporation's valuation and the book value of the long-term other
asset.
In July 2012 the Belize Supreme Court dismissed the Corporation's claim of
October 2011. Also in July 2012, Fortis filed its appeal of the above-noted
trial judgment in the Belize Court of Appeal. The appeal was heard in October
2012 and a decision is pending. Any decision of the Belize Court of Appeal may
be appealed to the Caribbean Court of Justice, the highest court of appeal
available for judicial matters in Belize.
Fortis believes it has a strong, well-positioned case before the Belize Courts
supporting the unconstitutionality of the expropriation. There exists, however,
a reasonable possibility that the outcome of the litigation may be unfavourable
to the Corporation and the amount of compensation otherwise to be paid to Fortis
under the legislation expropriating Belize Electricity could be lower than the
book value of the Corporation's expropriated investment in Belize Electricity.
The book value was $105 million, including foreign exchange impacts, as at
September 30, 2013 (December 31, 2012 - $104 million). If the expropriation is
held to be unconstitutional, it is not determinable at this time as to the
nature of the relief that would be awarded to Fortis, for example: (i) the
ordering of the return of the shares to Fortis and/or award of damages; or (ii)
the ordering of compensation to be paid to Fortis for the unconstitutional
expropriation of the shares. Based on presently available information, the $105
million long-term other asset is not deemed impaired as at September 30, 2013.
Fortis will continue to assess for impairment each reporting period based on
evaluating the outcomes of court proceedings and/or compensation settlement
negotiations. As well as continuing the constitutional challenge of the
expropriation, Fortis is also pursuing alternative options for obtaining fair
compensation, including compensation under the Belize/United Kingdom Bilateral
Investment Treaty.
23. CONTINGENT LIABILITIES
The Corporation and its subsidiaries are subject to various legal proceedings
and claims associated with the ordinary course of business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed settlement
agreement with counsel to plaintiff shareholders pertaining to several
complaints, which named Fortis and other defendants, which were filed in, or
transferred to, the Supreme Court of the State of New York, County of New York,
relating to the acquisition of CH Energy Group by Fortis. The complaints
generally alleged that the directors of CH Energy Group breached their fiduciary
duties in connection with the acquisition and that CH Energy Group, Fortis,
FortisUS Inc. and Cascade Acquisition Sub Inc. aided and abetted that breach.
The settlement agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from CRA for additional taxes related to the taxation years 1999
through 2003. The exposure has been fully provided for in the consolidated
financial statements. A settlement was reached with CRA in the second quarter of
2013 resulting in the release of income tax provisions of approximately $5
million (Note 12).
In April 2013 FHI and Fortis were named as defendants in an action in the
British Columbia Supreme Court by the Coldwater Indian Band ("Band"). The claim
is in regard to interests in a pipeline right of way on reserve lands. The
pipeline on the right of way was transferred by FHI (then Terasen Inc.) to
Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of
way and claims damages for wrongful interference with the Band's use and
enjoyment of reserve lands. The outcome cannot be reasonably determined and
estimated at this time and, accordingly, no amount has been accrued in the
interim unaudited consolidated financial statements.
FortisBC Electric
The Government of British Columbia has alleged breaches of the Forest Practices
Code and negligence relating to a forest fire near Vaseux Lake in 2003, prior to
the acquisition of FortisBC Electric by Fortis, and has filed and served a writ
and statement of claim against FortisBC Electric dated August 2, 2005. The
Government of British Columbia has now disclosed that its claim includes
approximately $15 million in damages as well as pre-judgment interest, but that
it has not fully quantified its damages. FortisBC Electric and its insurers
continue to defend the claim by the Government of British Columbia. The outcome
cannot be reasonably determined and estimated at this time and, accordingly, no
amount has been accrued in the interim unaudited consolidated financial
statements.
The Government of British Columbia filed a claim in the British Columbia Supreme
Court in June 2012 claiming on its behalf, and on behalf of approximately 17
homeowners, damages suffered as a result of a landslide caused by a dam failure
in Oliver, British Columbia in 2010. The Government of British Columbia alleges
in its claim that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government of British
Columbia estimates its damages and the damages of the homeowners, on whose
behalf it is claiming, to be approximately $15 million. While FortisBC Electric
has not been served, the utility has retained counsel and has notified its
insurers. The outcome cannot be reasonably determined and estimated at this time
and, accordingly, no amount has been accrued in the interim unaudited
consolidated financial statements.
Central Hudson
Danskammer Point Steam Electric Generating Station
In 1999, the New York State Attorney General alleged that Central Hudson may
have constructed, and continued to operate, major modifications to the
Danskammer Point Steam Electric Generating Station ("Danskammer Plant") without
obtaining certain requisite pre-construction permits. In March 2000, the
Environmental Protection Agency assumed responsibility for the investigation.
Central Hudson believes any permits required for these projects were obtained in
a timely manner. The Company sold the Danskammer Plant to Dynegy Inc. in January
2001. While Central Hudson could have retained liability after the sale,
depending on the type of remedy, the Company believes that the statutes of
limitation relating to any alleged violation of air emissions rules have lapsed.
Former MGP Facilities
Central Hudson and its predecessors owned and operated MGPs to serve their
customers' heating and lighting needs. These plants manufactured gas from coal
and oil beginning in the mid to late 1800's with all sites ceasing operations by
the 1950's. This process produced certain by-products that may pose risks to
human health and the environment.
The New York State Department of Environmental Conservation ("DEC"), which
regulates the timing and extent of remediation of MGP sites in New York State,
has notified Central Hudson that it believes the Company or its predecessors at
one time owned and/or operated MGPs at seven sites in Central Hudson's franchise
territory. The DEC has further requested that the Company investigate and, if
necessary, remediate these sites under a Consent Order, Voluntary Clean-up
Agreement, or Brownfield Clean-up Agreement. Central Hudson accrues for
remediation costs based on the amounts that can be reasonably estimated. As at
September 30, 2013, an obligation of US$8 million was recognized in respect of
MGPs remediation and, based upon cost model analysis completed in 2012, it is
estimated, with a 90% confidence level, that total costs to remediate these
sites over the next 30 years will not exceed US$152 million.
Central Hudson has notified its insurers and intends to seek reimbursement from
insurers for remediation, where coverage exists. Further, as authorized by the
PSC, Central Hudson is currently permitted to defer, for future recovery from
customers, the differences between actual costs for MGP site investigation and
remediation and the associated rate allowances, with carrying charges to be
accrued on the deferred balances at the authorized pre-tax rate of return (Note
4).
Eltings Corners
Central Hudson owns and operates a maintenance and warehouse facility. In the
course of Central Hudson's hazardous waste permit renewal process for this
facility, sediment contamination was discovered within the wetland area across
the street from the main property. In cooperation with the DEC, Central Hudson
continues to investigate the nature and extent of the contamination. The extent
of the contamination, as well as the timing and costs for any future remediation
efforts, cannot be reasonably estimated at this time and, accordingly, no amount
has been accrued in the interim unaudited consolidated financial statements.
Asbestos Litigation
Prior to the acquisition of CH Energy Group, various asbestos lawsuits had been
brought against Central Hudson. While a total of 3,341 asbestos cases have been
raised, 1,169 remained pending as at September 30, 2013. Of the cases no longer
pending against Central Hudson, 2,017 have been dismissed or discontinued
without payment by the Company, and Central Hudson has settled the remaining 155
cases. The Company is presently unable to assess the validity of the remaining
asbestos lawsuits; however, based on information known to Central Hudson at this
time, including the Company's experience in the settlement and/or dismissal of
asbestos cases, Central Hudson believes that the costs which may be incurred in
connection with the remaining lawsuits will not have a material effect on its
financial position, results of operations or cash flows and, accordingly, no
amount has been accrued in the interim unaudited consolidated financial
statements.
24. SUBSEQUENT EVENT
In October 2013 the Corporation issued 10-year US$285 million unsecured notes at
3.84% and 30-year US$40 million unsecured notes at 5.08%. Proceeds from the
offering were used to repay a portion of the Corporation's US dollar-denominated
credit facility borrowings incurred to initially finance a portion of the CH
Energy Group acquisition and for general corporate purposes.
25. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
presentation.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned gas and electric distribution utility
in Canada. Its regulated utilities account for 90% of total assets and serve
more than 2.4 million customers across Canada and in New York State and the
Caribbean. Fortis owns non-regulated hydroelectric generation assets in Canada,
Belize and Upstate New York. The Corporation's non-utility investments are
comprised of hotels and commercial real estate in Canada and petroleum supply
operations in the Mid-Atlantic Region of the United States.
The Common Shares; First Preference Shares, Series E; First Preference Shares,
Series F; First Preference Shares, Series G; First Preference Shares, Series H;
First Preference Shares, Series J; and First Preference Shares, Series K are
listed on the Toronto Stock Exchange and trade under the ticker symbols FTS,
FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.J, and FTS.PR.K, respectively.
Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.investorcentre.com/fortisinc
Additional information, including the Fortis 2012 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.
FOR FURTHER INFORMATION PLEASE CONTACT:
Barry V. Perry
Vice President Finance and Chief Financial Officer
Fortis Inc.
709.737.2822
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