Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter
net earnings attributable to common equity shareholders of $54 million, or $0.28
per common share, compared to $62 million, or $0.33 per common share, for the
second quarter of 2012. For the first half of 2013, net earnings attributable to
common equity shareholders were $205 million, or $1.06 per common share,
compared to $183 million, or $0.97 per common share, for the first half of last
year.
On June 27, 2013, Fortis closed the acquisition of CH Energy Group, Inc. ("CH
Energy Group") for approximately US$1.5 billion, including the assumption of
US$518 million of debt on closing. The net purchase price of the acquisition was
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 377,000 electric and
gas customers in New York State's Mid-Hudson River Valley. Earnings for the
quarter were reduced by $32 million, or $0.17 per common share, due to
acquisition-related expenses and customer and community benefits offered to
obtain regulatory approval of the acquisition compared to $3 million of
acquisition-related expenses for the same period last year.
Earnings for the quarter were favourably impacted by an income tax recovery of
$25 million, or $0.13 per common share, 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 attributable to common equity shareholders for the second quarter of
2013 were $61 million, or $0.32 per common share, compared to $68 million, or
$0.36 per common share, for the second quarter of 2012.
"The integration of Central Hudson into the Fortis Group is progressing well,"
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, including Central Hudson, comprise approximately 90% of
total assets and serve approximately 2.4 million gas and electricity customers
across Canada and in New York State and the Caribbean. Regulated rate base
assets of Fortis exceed $10 billion.
Canadian Regulated Gas Utilities contributed earnings of $6 million compared to
$13 million for the second quarter of 2012. The $7 million decrease in earnings
reflects the $8 million unfavourable impact for the first half of 2013 of the
regulatory decision related to the first phase of the Generic Cost of Capital
("GCOC") Proceeding in British Columbia, described more fully below, which was
recognized in the second quarter of 2013 when the decision was received.
Earnings contribution from growth in energy infrastructure investment was
largely offset by lower gas transportation volumes to industrial customers and
lower-than-expected customer additions.
Canadian Regulated Electric Utilities contributed earnings of $66 million, up
$15 million from the second quarter of 2012. For the second quarter, earnings at
Newfoundland Power and Maritime Electric were favourably impacted by income tax
recoveries of $13 million and $4 million, respectively, associated with Part
VI.1 tax. FortisAlberta's earnings decreased $1 million, due to lower net
transmission revenue and timing of the recognition of a regulatory decision in
2012 impacting depreciation, partially offset by timing of operating expenses,
growth in energy infrastructure investment and customer growth. The utility's
depreciation rates were reduced, effective January 1, 2012, as a result of the
decision related to FortisAlberta's 2012 revenue requirements, the impact of
which was not recognized until the second quarter of 2012 when the decision was
received. FortisBC Electric's earnings were $1 million lower quarter over
quarter, due to the $2 million unfavourable impact for the first half of 2013 of
the regulatory decision related to the first phase of the GCOC Proceeding, which
was recognized in the second quarter of 2013 when the decision was received,
partially offset by lower-than-expected finance charges, growth in energy
infrastructure investment and higher capitalized allowance for funds used during
construction.
In May 2013 the British Columbia Utilities Commission issued its decision on the
first phase of its GCOC Proceeding. As a result, the allowed rate of return on
common shareholders' equity ("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% for 2013 through 2015. The
interim allowed ROEs for the other FortisBC Energy companies, FortisBC Energy
(Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI"),
and for 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 the 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.
In April 2013 Newfoundland Power received a cost of capital decision maintaining
the utility's allowed ROE and common equity component of capital structure at
8.8% and 45%, respectively, for 2013 through 2015. FortisAlberta's allowed ROE
and capital structure for 2013 remain to be determined.
Caribbean Regulated Electric Utilities contributed $6 million of earnings,
comparable with the second quarter of 2012.
Non-Regulated Fortis Generation contributed $3 million of earnings compared to
$6 million for the second quarter of 2012. The $3 million decrease in earnings
is mainly related to lower production in Belize due to lower rainfall.
Non-Utility operations contributed earnings of $9 million, $1 million higher
than earnings for the second quarter of 2012, largely related to performance at
Fortis Properties' hotels in western Canada.
Corporate and other expenses were $36 million compared to $22 million for the
second quarter of 2012. Corporate and other expenses for the second quarter of
2013 included $32 million in CH Energy Group transaction expenses, compared to
$3 million for the same quarter last year. An approximate $8 million income tax
recovery, associated with Part VI.1 tax, reduced Corporate and other expenses in
the second quarter of 2013, compared to income tax expense of $3 million
associated with Part VI.1 tax for the same quarter last year. Excluding the
above-noted impacts, Corporate and other expenses were $4 million lower, quarter
over quarter, mainly 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.
Consolidated capital expenditures, before customer contributions, were
approximately $548 million for the first half of 2013 and are expected to total
approximately $1.3 billion for the year. Construction of the $900 million,
335-megawatt Waneta Expansion hydroelectric generating facility ("Waneta
Expansion") in British Columbia continues on time and on budget, with completion
of the facility expected in spring 2015. Approximately $513 million in total has
been invested in the Waneta Expansion since construction began in late 2010.
Cash flow from operating activities was $571 million for the first half of 2013
compared to $583 million for the first half of 2012.
Fortis has consolidated credit facilities of $2.7 billion, of which $1.7 billion
was unused as at June 30, 2013. Credit facility borrowings as at June 30, 2013
include $605 million in drawings under the Corporation's committed credit
facility. In July 2013 Fortis issued 10 million Cumulative Redeemable Fixed Rate
Reset First Preference Shares, Series K for gross proceeds of $250 million, the
proceeds of which 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. In July 2013 the
Corporation also priced 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 offering
is scheduled to close on October 1, 2013. Proceeds from the offering will be
used to repay a portion of US dollar-denominated committed credit facility
borrowings incurred to initially finance a portion of the CH Energy Group
acquisition.
"The second half of 2013 will continue to be very busy for Fortis, with
significant regulatory proceedings in British Columbia and Alberta and with work
continuing on capital projects for the year to ensure we continue to meet our
customers' energy needs. Our five-year capital program, including Central
Hudson, is projected to total $6 billion, which is expected to drive growth in
earnings and dividends," explains Marshall.
"We welcome the employees of Central Hudson to the Fortis team, now some 8,400
individuals strong. The addition of this well-run U.S. utility and its proven
track record for providing customers with quality service will further enhance
the positioning of Fortis as a leader in the North American utility industry,"
concludes Marshall.
Interim Management Discussion and Analysis
For the three and six months ended June 30, 2013
Dated August 1, 2013
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 six months ended June 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 forecasted 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 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 on average annually 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. ("CH Energy Group")
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 accounting principles generally accepted in the United
States 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 each 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
approximately 2.4 million gas and electricity 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 June 30, 2013, the Corporation's electricity distribution systems
met a combined peak demand of approximately 5,159 megawatts ("MW") and its gas
distribution system met a peak day demand of 1,113 terajoules ("TJ"). For
additional information on the Corporation's business segments, refer to Note 1
to the Corporation's interim unaudited consolidated financial statements for the
three and six months ended June 30, 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 forecasted 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 electric and 77,000 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 mainly consist
of Griffith Energy Services, Inc. ("Griffith"), which is primarily a fuel
delivery business serving approximately 56,000 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, including certain
storm-restoration expenses; (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, electric 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, including an estimated US$50 million which will have a
"storm-hardening" effect on its infrastructure.
The above-noted commitments of US$35 million and US$5 million, together with
acquisition-related expenses of approximately US$8 million, have been 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.
Part VI.1 Tax: 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. 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.
In April 2013 Newfoundland Power received a cost of capital decision maintaining
the utility's allowed ROE and common equity component of capital structure at
8.8% and 45%, respectively, for 2013 through 2015.
In May 2013 the British Columbia Utilities Commission ("BCUC") issued its
decision on the first phase of its Generic Cost of Capital ("GCOC") Proceeding
for British Columbia utilities. As a result, the allowed ROE for FortisBC Energy
Inc. ("FEI"), which is the benchmark utility for calculating the allowed ROE for
certain utilities in British Columbia, 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% for 2013 through 2015. The interim allowed ROEs for
the other FortisBC Energy companies, FortisBC Energy (Vancouver Island) Inc.
("FEVI") and 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 the 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.
For a 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 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 $55 million in March 2013, which now allows FortisBC
Electric to directly serve some 15,000 customers formerly served by the City.
FortisBC Electric had provided the City with electricity under a wholesale
tariff and had operated and maintained the City's electrical utility assets
under contract since 2000.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the second quarter and
year-to-date periods ended June 30, 2013 and June 30, 2012 are provided in the
following table.
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Consolidated Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except for
common share data) 2013 2012 Variance 2013 2012 Variance
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Revenue 790 792 (2) 1,903 1,941 (38)
Energy Supply Costs 282 291 (9) 787 857 (70)
Operating Expenses 206 204 2 427 418 9
Depreciation and
Amortization 130 114 16 259 233 26
Other Income (Expenses),
Net (44) - (44) (38) (3) (35)
Finance Charges 92 92 - 181 183 (2)
Income Tax (Recovery)
Expense (34) 14 (48) (4) 37 (41)
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Earnings Before
Extraordinary Item 70 77 (7) 215 210 5
Extraordinary Gain, Net
of Tax - - - 22 - 22
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Net Earnings 70 77 (7) 237 210 27
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Net Earnings
Attributable to:
Non-Controlling
Interests 2 3 (1) 4 4 -
Preference Equity
Shareholders 14 12 2 28 23 5
Common Equity
Shareholders 54 62 (8) 205 183 22
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Net Earnings 70 77 (7) 237 210 27
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Earnings per Common
Share Before
Extraordinary Item
Basic ($) 0.28 0.33 (0.05) 0.95 0.97 (0.02)
Diluted ($) 0.28 0.33 (0.05) 0.94 0.95 (0.01)
Earnings per Common
Share
Basic ($) 0.28 0.33 (0.05) 1.06 0.97 0.09
Diluted ($) 0.28 0.33 (0.05) 1.05 0.95 0.10
Weighted Average Common
Shares Outstanding (#
millions) 193.4 189.6 3.8 192.7 189.3 3.4
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Cash Flow from Operating
Activities 291 255 36 571 583 (12)
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Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Unfavourable
-- Lower commodity cost of natural gas charged to customers at the FortisBC
Energy companies
-- 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 as a result of the BCUC decision in May 2013 on the
first phase of its GCOC Proceeding
-- Lower average gas consumption by residential and commercial customers
and lower gas transportation volumes to industrial customers at the
FortisBC Energy companies
-- Decreased non-regulated hydroelectric production in Belize, due to lower
rainfall
-- Lower net transmission revenue at FortisAlberta
Favourable
-- 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 Newfoundland Power, Maritime Electric,
Fortis Turks and Caicos and Caribbean Utilities
Factors Contributing to Quarterly and Year-to-Date Energy Supply Costs Variances
Favourable
-- Lower commodity cost of natural gas
-- Lower average gas consumption by residential and commercial customers
and lower gas transportation volumes to industrial customers at the
FortisBC Energy companies, which reduced natural gas purchases
Unfavourable
-- Increased electricity sales at Newfoundland Power, Maritime Electric,
Fortis Turks and Caicos and Caribbean Utilities, which increased fuel
and power purchases
-- Increased costs at Maritime Electric associated with energy supply costs
expensed in the first half of 2013 related to the New Brunswick Power
Point Lepreau nuclear generating station ("Point Lepreau"), which
returned to service in the fourth quarter of 2012
Factor Contributing to Quarterly and Year-to-Date Operating Expenses Variances
Unfavourable
-- General inflationary and employee-related cost increases at most of the
Corporation's regulated utilities
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
-- Lower depreciation rates at FortisAlberta, effective January 1, 2012, as
a result of the 2012 distribution revenue requirements decision received
in April 2012. The cumulative impact of the overall decrease in
depreciation rates was recognized in the second quarter of 2012, when
the decision was received. Approximately $3 million of decreased
depreciation expense related to the first quarter of 2012.
Factors Contributing to Quarterly and Year-to-Date Other Income (Expenses), Net
Variances
Unfavourable
-- 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
-- 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 $4 million ($3 million after tax) and $8
million ($7 million after tax) for the second quarter and first half of
2012, respectively
Favourable
-- Foreign exchange gains of approximately $3 million and $5 million for
the second quarter and the first half of 2013, respectively, associated
with the translation of the US dollar-denominated long-term other asset
representing the book value of the Corporation's expropriated investment
in Belize Electricity, compared to approximately $2 million and $0.5
million, respectively, for the same periods in 2012
Factors Contributing to Quarterly and Year-to-Date Finance Charges Variances
Favourable
-- Higher capitalized interest associated with the financing of the
construction of the Corporation's 51% controlling ownership interest in
the Waneta Expansion hydroelectric generating facility ("Waneta
Expansion")
-- Higher capitalized allowance for funds used during construction
("AFUDC"), mainly at FortisBC Electric
Unfavourable
-- Higher long-term debt levels in support of the utilities' capital
expenditure programs
Factors Contributing to Quarterly and Year-to-Date Income Tax (Recovery) 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, compared to income tax expense of $3 million associated with
Part VI.1 tax for the same quarter last year. In the first quarter of
2013, income tax expense included $2 million associated with Part VI.1
tax.
-- An approximate $5 million income tax recovery associated with the
release of income tax provisions in the second quarter of 2013
Unfavourable
-- Higher effective income taxes, due to differences in the deductions for
income tax purposes compared to accounting purpose, mainly at the
FortisBC Energy companies and FortisBC Electric
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 Exploits Partnership
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher corporate expenses due to $32 million in CH Energy Group
transaction expenses and higher preference share dividends, due to the
issuance of First Preference Shares, Series J in November 2012. The
increases were partially offset by: (i) income tax recoveries of
approximately $13 million, comprised of $8 million associated with Part
VI.1 tax and $5 million associated with the release of income tax
provisions in the second quarter of 2013; (ii) a higher 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. In the first quarter of 2013, income tax expense included $2
million associated with Part VI.1 tax.
-- Decreased earnings at the FortisBC Energy companies primarily due to:
(i) the $8 million unfavourable impact for the first half of 2013 of the
regulatory decision in May 2013 related to the first phase of the GCOC
Proceeding; (ii) lower gas transportation volumes to industrial
customers; 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 the $2 million
unfavourable impact for the first half of 2013 of the regulatory
decision in May 2013 related to first phase of the GCOC Proceeding,
partially offset by lower-than-expected finance charges, growth in
energy infrastructure investment and higher capitalized AFUDC
-- Decreased non-regulated hydroelectric production in Belize, due to lower
rainfall
-- Decreased earnings at FortisAlberta due to lower net transmission
revenue and timing of the recognition of a regulatory decision in 2012
impacting depreciation, partially offset by timing of operating
expenses, growth in energy infrastructure investment and customer growth
Favourable
-- Increased earnings at Newfoundland Power and Maritime Electric due to
income tax recoveries of $13 million and $4 million, respectively,
associated with Part VI.1 tax
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- An approximate $22 million after-tax extraordinary gain recognized in
the first quarter of 2013 on the settlement of expropriation matters
associated with the Exploits Partnership
-- Increased earnings at Newfoundland Power and Maritime Electric due to
income tax recoveries associated with Part VI.1 tax, as discussed above
-- Increased earnings at FortisAlberta, due to timing of operating
expenses, growth in energy infrastructure investment and customer
growth, partially offset by lower net transmission revenue
Unfavourable
-- Higher corporate expenses, for the same reasons discussed above for the
quarter
-- Decreased earnings at the FortisBC Energy companies, for the same
reasons discussed above for the quarter, as well as higher effective
income taxes
-- Decreased non-regulated hydroelectric production in Belize, due to lower
rainfall
SEGMENTED RESULTS OF OPERATIONS
The basis of segmentation of the Corporation's reportable segments is consistent
with that disclosed in the 2012 Annual MD&A, except as follows as a result of
the acquisition of CH Energy Group. Central Hudson is reported in a new segment
"Regulated Gas & Electric Utility - United States"; and the former
"Non-Regulated - Fortis Properties" segment is now "Non Regulated - Non-Utility"
and is comprised of Fortis Properties and Griffith, the non-regulated operations
of CH Energy Group.
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy Companies 6 13 (7) 91 95 (4)
----------------------------------------------------------------------------
Regulated Gas & Electric
Utility - United States
Central Hudson - - - - - -
----------------------------------------------------------------------------
Regulated Electric Utilities
- Canadian
FortisAlberta 25 26 (1) 51 47 4
FortisBC Electric 8 9 (1) 26 25 1
Newfoundland Power 24 11 13 31 18 13
Other Canadian Electric
Utilities 9 5 4 15 12 3
----------------------------------------------------------------------------
66 51 15 123 102 21
----------------------------------------------------------------------------
Regulated Electric Utilities
- Caribbean 6 6 - 9 9 -
Non-Regulated - Fortis
Generation 3 6 (3) 27 11 16
Non-Regulated - Non-Utility 9 8 1 9 9 -
Corporate and Other (36) (22) (14) (54) (43) (11)
----------------------------------------------------------------------------
Net Earnings Attributable to
Common Equity Shareholders 54 62 (8) 205 183 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas Volumes (petajoules
("PJ")) 36 40 (4) 107 112 (5)
Revenue ($ millions) 246 264 (18) 738 812 (74)
Earnings ($ millions) 6 13 (7) 91 95 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 to industrial customers
As at June 30, 2013, the total number of customers served by the FortisBC Energy
companies was approximately 947,000. Net customer additions for the first half
of 2013 were approximately 2,000, comparable to the first half of 2012.
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
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Decreases in the allowed ROE and the equity component of capital
structure, 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 to industrial customers
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
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Decreases in the allowed ROE and the equity component of the capital
structure, as discussed above. The cumulative impact of the decision,
effective January 1, 2013, of approximately $8 million was recognized in
the second quarter when the decision was received.
-- Lower gas transportation volumes to industrial customers
-- Lower-than-expected customer additions
-- Higher effective income taxes, due to differences in the deductions for
income tax purposes compared to accounting purposes
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
REGULATED GAS & ELECTRIC UTILITY - UNITED STATES
CENTRAL HUDSON
Central Hudson is a regulated T&D utility serving approximately 300,000 electric
and 77,000 natural gas customers in eight counties of New York State's
Mid-Hudson River Valley. The Company's electric assets, which comprise
approximately 77% of its total assets as at June 30, 2013, include over 11,700
kilometres of distribution lines and approximately 2,300 kilometres of
transmission lines. The electric business met a peak demand of 1,168 MW in 2012.
Central Hudson's natural gas assets, which comprise the remaining 23% of its
total assets as at June 30, 2013, 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 115 TJ in 2012.
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 from a number of suppliers
at various receipt points on pipelines that it has contracted with 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
provides for the use of a future test year in the establishment 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 share equally
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 also 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.
Financial Highlights
The financial statements of Central Hudson have been included in the
consolidated financial statements of Fortis commencing June 27, 2013, the date
of acquisition. Other than expenses associated with customer and community
benefits offered by the Corporation to close the acquisition of CH Energy Group
reported in the Corporate and Other segment, financial performance for Central
Hudson from the date of acquisition through June 30, 2013 did not have a
material impact on the Corporation's consolidated statement of earnings.
Seasonality impacts the delivery revenues of Central Hudson, as sales of
electricity are highest during the summer months, primarily due to the use of
air conditioning and other cooling equipment, and sales of natural gas are
highest during the winter months, primarily due to space heating usage.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (gigawatt
hours ("GWh")) 3,995 3,853 142 8,486 8,335 151
Revenue ($ millions) 117 110 7 235 218 17
Earnings ($ millions) 25 26 (1) 51 47 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date Energy Deliveries Variances
Favourable
-- Growth in the number of customers, with the total number of customers
increasing by approximately 10,000 year over year as at June 30, 2013,
driven by favourable economic conditions and a high commodity price for
oil
-- Higher average consumption by commercial and residential customers, due
to cooler temperatures
Unfavourable
-- Lower average consumption by oil and gas customers, mainly in the first
quarter of 2013, due to decreased activity associated with a low
commodity price for natural gas
-- Lower average consumption by farm and irrigation customers, primarily
due to increased rainfall in the second quarter of 2013
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 approximately $3 million of
favourable volume variances recognized in the second quarter of 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 Earnings Variance
Unfavourable
-- Lower net transmission revenue of approximately $3 million, as discussed
above
-- Lower depreciation rates, effective January 1, 2012, as a result of the
2012 distribution revenue requirements decision received in April 2012.
The cumulative impact of the overall decrease in depreciation rates was
recognized in the second quarter of 2012, when the decision was
received. Approximately $3 million of decreased depreciation expense
related to the first quarter of 2012.
Favourable
-- Timing of operating expenses
-- Rate base growth, due to continued investment in energy infrastructure
-- Growth in the number of customers
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors discussed above for the quarter
Unfavourable
-- Lower net transmission revenue of approximately $1 million, as discussed
above
In June 2013 parts of FortisAlberta's service territory were impacted by the
flooding in southern Alberta. Restoration efforts related to the flood did not
have a material impact on the consolidated financial statements for the three
and six months ended June 30, 2013. Restoration efforts are ongoing and the
final impact on FortisAlberta's operations, assets, earnings and cash flow is
not fully determinable at this time.
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 681 676 5 1,572 1,585 (13)
Revenue ($ millions) 68 67 1 156 154 2
Earnings ($ millions) 8 9 (1) 26 25 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.
Factor Contributing to Quarterly Electricity Sales Variance
Favourable
-- Higher average consumption, due to cooler temperatures in the second
quarter of 2012
Factor Contributing to Year-to-Date Electricity Sales Variance
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
Unfavourable
-- Differences in the amortization to revenue of flow-through adjustments
owing to customers period over period
-- A decrease in the interim allowed ROE, as a result of the regulatory
decision in May 2013 related to the first phase of the GCOC Proceeding
-- Lower contribution from non-regulated operating, maintenance and
management services
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- A decrease in the interim allowed ROE, as discussed above. The
cumulative impact of the decision, effective January 1, 2013, of
approximately $2 million was recognized in the second quarter when the
decision was received.
-- Higher effective income taxes, due to lower deductions for income tax
purposes
Favourable
-- Lower-than-expected finance charges
-- Rate base growth, due to continued investment in energy infrastructure,
including the acquisition of the City of Kelowna's electrical utility
assets in March 2013
-- Higher capitalized AFUDC, as approved by the regulator
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 1,288 1,259 29 3,230 3,173 57
Revenue ($ millions) 132 130 2 329 322 7
Earnings ($ millions) 24 11 13 31 18 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date Electricity Sales Variances
Favourable
-- Growth in the number of customers
-- Higher average consumption, reflecting the higher use of electric-
versus-oil heating in new home construction combined with economic
growth
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 2.3% and 1.8% increase in electricity sales for the quarter and year
to date, respectively
Unfavourable
-- Lower amortization to revenue of regulatory liabilities and deferrals,
as approved by the regulator
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- An approximate $13 million income tax recovery in the second quarter of
2013, due to the enactment of higher deductions associated with Part
VI.1 tax
-- Rate base growth, due to continued investment in energy infrastructure
-- Electricity sales growth
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 558 563 (5) 1,229 1,208 21
Revenue ($ millions) 87 82 5 183 173 10
Earnings ($ millions) 9 5 4 15 12 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 in the second quarter
of 2013, 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
-- Higher average consumption by commercial customers in the agricultural
processing sector on PEI, primarily during the second quarter of 2013
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 in the second quarter of 2013
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- An approximate $4 million income tax recovery at Maritime Electric in
the second quarter of 2013, due to the enactment of higher deductions
associated with Part VI.1 tax
-- Electricity sales growth at Maritime Electric
Unfavourable
-- Timing of the recognition of a regulatory rate of return adjustment at
Maritime Electric in 2013 as compared to 2012
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate
(2) 1.02 1.01 0.01 1.01 1.01 -
----------------------------------------------------------------------------
Electricity Sales (GWh) 193 184 9 363 350 13
Revenue ($ millions) 70 67 3 136 130 6
Earnings ($ millions) 6 6 - 9 9 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 10 GWh of electricity sales in the second
quarter and first half of 2013, respectively, at TCU, which was acquired
in August 2012, partially offset by lower average consumption by
commercial customers at FortisTCI, mainly due to higher fuel costs and
resulting energy conservation
-- Growth in the number of customers at Caribbean Utilities and lower
rainfall experienced on Grand Cayman, which increased air conditioning
load
Factors Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- The 4.9% and 3.7% increase in electricity sales for the quarter and year
to date, respectively
-- An increase in electricity rates for FortisTCI's large hotel customers,
effective April 1, 2012
-- 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
-- Increased electricity sales at Caribbean Utilities
-- Decreased operating expenses at Caribbean Utilities, mainly due to lower
employee-related costs and maintenance costs
Unfavourable
-- Overall higher depreciation expense, due to continued investment in
energy infrastructure
-- Decreased electricity sales at FortisTCI
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 83 87 (4) 138 175 (37)
Revenue ($ millions) 7 9 (2) 12 18 (6)
Earnings ($ millions) 3 6 (3) 27 11 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
Unfavourable
-- Decreased production in Belize, due to lower rainfall
Favourable
-- Increased production in Ontario, Upstate New York and British Columbia,
due to higher rainfall, and a generating unit in New York State being
returned to service for part of the second quarter of 2013
Factor Contributing to Quarterly and Year-to-Date Revenue Variances
Unfavourable
-- Decreased production in Belize
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Unfavourable
-- Decreased production in Belize
Favourable
-- An approximate $22 million after-tax extraordinary gain recognized in
the first quarter of 2013 on the settlement of expropriation matters
associated with Exploits Partnership. For further information refer to
the "Significant Items" section of this MD&A.
Since the end of the second quarter of 2013, a tropical depression that passed
over Belize provided enough precipitation to fill the Chalillo reservoir. The
hydroelectric generating facilities in Belize are currently running at full
capacity.
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 mainly consist of Griffith, which is
primarily a fuel delivery business serving approximately 56,000 customers in the
Mid-Atlantic Region of the United States.
Fortis Properties
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality - Revenue
per Available Room
("RevPar") $87.76 $85.56 2.6% $76.96 $76.05 1.2%
Real Estate - Occupancy
Rate (as at) 92.3% 91.7% 0.7% 92.3% 91.7% 0.7%
----------------------------------------------------------------------------
Revenue ($ millions) 65 64 1 118 116 2
Earnings ($ millions) 9 8 1 9 9 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly RevPar Variance
Favourable
-- A 1.6% increase in occupancy, driven by hotel operations in western
Canada
-- A 1.0% increase in the average daily room rate, mainly in western Canada
Factor Contributing to Year-to-Date RevPar Variance
Favourable
-- A 1.5% increase in the average daily room rate, mainly in western
Canada, partially offset by a 0.3% decrease in occupancy, mainly at
hotel operations in central Canada
Factor Contributing to Quarterly and Year-to-Date Revenue Variances
Favourable
-- Increased revenue at the Hospitality Division, mainly due to
contribution from the StationPark All Suite Hotel, which was acquired in
October 2012, and hotel operations in western Canada
Factors Contributing to Quarterly and Year-to-Date Earnings Variances
Favourable
-- Improved performance at the Hospitality Division, primarily due to hotel
operations in western Canada
Unfavourable
-- Increased depreciation, due to capital additions and improvements
Griffith
Griffith is an indirect wholly owned subsidiary of CH Energy Group, which
supplies heating oil, gasoline, diesel fuel, kerosene and propane to
approximately 56,000 customers in Maryland, Delaware, Washington D.C. and
Virginia in the United States. Griffith also installs and maintains heating,
ventilating and air conditioning equipment in these markets, which includes a
customer base of an additional 12,000.
The financial statements of Griffith have been included in the consolidated
financial statements of Fortis commencing June 27, 2013, the date of
acquisition. Financial performance for Griffith from the date of acquisition
through June 30, 2013 did not have a material impact on the Corporation's
consolidated statement of earnings.
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.
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 7 7 - 13 13 -
Operating Expenses 3 3 - 6 6 -
Depreciation and
Amortization - - - 1 1 -
Other Income (Expenses), Net (46) (3) (43) (44) (8) (36)
Finance Charges 11 12 (1) 21 23 (2)
Income Tax Recovery (31) (1) (30) (33) (5) (28)
----------------------------------------------------------------------------
(22) (10) (12) (26) (20) (6)
Preference Share Dividends 14 12 2 28 23 5
----------------------------------------------------------------------------
Net Corporate and Other
Expenses (36) (22) (14) (54) (43) (11)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 and Year-to-Date Net Corporate and Other
Expenses Variances
Unfavourable
-- Increased other expenses primarily due to: (i) approximately $41 million
(US$40 million), $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 $4 million ($3 million after
tax) and $8 million ($7 million after tax) for the second quarter and
first half of 2012, respectively. 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 foreign
exchange gains of approximately $3 million and $5 million for the second
quarter and the first half of 2013, respectively, associated with the
translation of the US dollar-denominated long-term other asset
representing the book value of the Corporation's expropriated investment
in Belize Electricity, compared to approximately $2 million and $0.5
million, respectively, for the same periods in 2012.
-- Higher preference share dividends, due to the issuance of First
Preference Shares, Series J in November 2012
Favourable
-- An approximate $8 million income tax recovery in the second quarter of
2013, due to the enactment of higher deductions associated with Part
VI.1 tax, compared to income tax expense of $3 million associated with
Part VI.1 tax for the same quarter last year. In the first quarter of
2013, income tax expense included $2 million associated with Part VI.1
tax.
-- An approximate $5 million income tax recovery associated with the
release of income tax provisions in the second quarter of 2013
-- Lower finance charges, primarily due to higher capitalized interest
associated with the financing of the construction of the Corporation's
51% controlling ownership interest in the Waneta Expansion
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the first half of 2013 are summarized as follows.
NATURE OF REGULATION
----------------------------------------------------------------------------
Supportive
Allowed Returns (%) Features
-------------------------------------------
Future or
Allowed Historical Test
Common Year
Regulated Regulatory Equity Used to Set
Utility Authority (%) 2011 2012 2013 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(3) COS/ROE
Hudson
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
----------------------------------------------------------------------------
Fortis- Alberta 41(4) 8.75 8.75 8.75(4) COS/ROE
Alberta 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
----------------------------------------------------------------------------
Newfound- Newfoundland 45 8.38 +/- 8.80 +/- 8.80 +/- COS/ROE
land and Labrador 50 bps 50 bps 50 bps
Power Board of
Commissioners
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
----------------------------------------------------------------------------
ROE Canadian Niagara
Power - COS/ROE
---------------------------
Fortis- Ontario Energy
Ontario Board ("OEB") Algoma Power -
COS/ROE and
subject to Rural
and Remote Rate
Protection
("RRRP") program
Canadian 40 8.01 8.01 8.93(5)
Niagara
Power
Algoma Power 40 9.85 9.85 9.85(5)
Cornwall
Franchise Electric - Price
Agreement cap with
commodity cost
flow through
----------------
Cornwall Canadian Niagara
Electric 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 Rate-cap
Authority adjustment
("ERA") mechanism based
on published
consumer price
indices
The Company may
apply for a
special
additional rate
to customers in
the event of a
disaster,
including a
hurricane.
----------------
Historical Test
Year
----------------------------------------------------------------------------
Fortis Utilities N/A 17.50(6) 17.50(6) 17.50(6) COS/ROA
Turks make annual
and filings to the
Caicos 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 the 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"),
partially offset by a decrease in midstream rates. Natural
gas commodity rates effective January 1, 2013 remained
unchanged for customers at FEI.
- 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
three 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 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 a decision on the rate to be charged to customers is
expected in the third 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 third quarter of 2013.
- 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 and has set out a regulatory timetable for
filing of evidence.
- 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 in
July 2013 FEVI, FEWI and FortisBC Electric filed evidence
in accordance with the review. A decision on the second
phase of the GCOC Proceeding is expected in the first half
of 2014. For further discussion on the nature of the GCOC
Proceeding, refer to the "Material Regulatory Decisions
and Applications" section of the Corporation's 2012 Annual
MD&A.
- In June 2013 FEI filed an application for a Multi-Year
Performance-Based Ratemaking Plan for 2014 through 2018.
The application assumes a forecast average rate base for
2014 of approximately $2,789 million. The application
requests approval of a delivery rate increase of
approximately 1% for 2014 determined under a formula
approach for operating and capital costs, and a
continuation of this rate-setting methodology for a
further four years. The review process for the application
will continue throughout 2013.
----------------------------------------------------------------------------
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. As a condition of the BCUC decision,
FortisBC Electric has confirmed that it will file, by
November 2013, an application for an opt-out provision
which would require the incremental cost of opting-out of
AMI to be borne by customers who choose to opt-out.
- 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 for
a Multi-Year Performance-Based Ratemaking Plan for 2014
through 2018. The application assumes a forecast midyear
rate base for 2014 of approximately $1,227 million. The
application 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 review process for the application
will continue throughout 2013.
----------------------------------------------------------------------------
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
to 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
2012 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. The Phase II DTA will continue as a
written proceeding with a decision expected in the third
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 specific flow-through amounts, and the
recovery, on an interim basis, of 60% of the revenue
requirement associated with the 2013 capital tracker
expenditures applied for by FortisAlberta. 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 commenced in June 2013, with a
decision expected in the second half 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. The AUC
may consider the possibility of re-establishing a
formulaic ROE automatic adjustment mechanism at this time.
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 its 2011 GCOC Decision, the AUC made statements
regarding cost responsibility for stranded assets, which
FortisAlberta and other utilities challenged as being
incorrectly made. 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
to 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 does not alter a utility's right to a
reasonable opportunity to recover prudent COS and the
right to earn a reasonable ROE. In July 2013
FortisAlberta, together with other Alberta utilities,
filed reply arguments in the UAD Proceeding, after which
the AUC will commence deliberations with a decision
expected in the fourth quarter of 2013.
----------------------------------------------------------------------------
Newfoundland - In April 2013 the PUB issued its decision related to
Power Newfoundland Power's 2013/2014 General Rate Application
("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 June 2013 Newfoundland Power filed an application
with the PUB requesting approval for its 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 due to 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 and
higher COS. 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-Rate Mechanism
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.
----------------------------------------------------------------------------
Caribbean - In June 2013 the ERA approved Caribbean Utilities' 2013-
Utilities 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
targeted allowed ROA for 2013.
----------------------------------------------------------------------------
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$105 million
as at December 31, 2012.
----------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheet between June 30, 2013 and December 31, 2012. The changes in the
consolidated balance sheet as at June 30, 2013 associated with the acquisition
of CH Energy Group are itemized separately below.
Significant Changes in the Consolidated Balance Sheet (Unaudited) between
June 30, 2013 and December 31, 2012
----------------------------------------------------------------------------
Increase Other
Due to Increase/
Balance Sheet CH Energy Group (Decrease) Explanation for Other
Account ($ millions) ($ millions) Increase/(Decrease)
----------------------------------------------------------------------------
Cash and cash 81 32 The increase in cash and
equivalents cash equivalents was not
significant.
----------------------------------------------------------------------------
Accounts 118 (114) The decrease was primarily
receivable due to the impact of a
seasonal decrease in sales
at the FortisBC Energy
companies, partially offset
by an increase due to the
operation of equal payment
plans.
----------------------------------------------------------------------------
Regulatory 271 (3) The decrease was mainly due
assets - to: (i) proceeds of
current and approximately $47 million
long-term received from the
Government of PEI in March
2013 upon its assumption of
Maritime Electric's
replacement energy deferral
associated with Point
Lepreau; and (ii) the $26
million change in the
deferral of the fair market
value of the natural gas
commodity derivatives at
the FortisBC Energy
companies. The above
decreases were partially
offset by an increase in
the rate stabilization
deferrals at the FortisBC
Energy companies, an
increase in regulatory
deferred income taxes, and
the deferral of various
other costs, as permitted
by the regulators, mainly
at the FortisBC utilities
and FortisAlberta.
----------------------------------------------------------------------------
Other assets 41 (3) The decrease in other
assets was not significant.
----------------------------------------------------------------------------
Utility capital 1,286 363 The increase primarily
assets related to: (i) $508
million invested in
electricity and gas
systems; (ii) the impact of
foreign exchange on the
translation of US dollar-
denominated utility capital
assets; and (iii) the
acquisition of the City of
Kelowna's electrical
utility assets by FortisBC
Electric. The above
increases were partially
offset by depreciation and
customer contributions.
----------------------------------------------------------------------------
Intangible 45 (9) The decrease in intangible
assets assets was not significant.
----------------------------------------------------------------------------
Goodwill 486 23 The increase in goodwill
was not significant.
----------------------------------------------------------------------------
Short-term 39 (76) The decrease was primarily
borrowings due to: (i) a reduction in
borrowings at the FortisBC
Energy companies due to the
seasonality of operations;
(ii) the repayment of
short-term borrowings at
Caribbean Utilities using
proceeds from the issuance
of long-term debt; and
(iii) the repayment of
borrowings at Maritime
Electric with a portion of
proceeds received from the
Government of PEI in March
2013.
----------------------------------------------------------------------------
Accounts payable 122 (126) The decrease was mainly due
and other to: (i) the timing of
current Alberta Electric System
liabilities Operator ("AESO") payments
for 2012 transmission costs
and lower accounts payable
associated with
transmission-connected
projects at FortisAlberta;
(ii) the $26 million change
in the fair market value of
the natural gas commodity
derivatives at the FortisBC
Energy companies; (iii) the
enactment of higher
deductions associated with
Part VI.1 tax, resulting in
the reversal of
approximately $23 million
in income tax liabilities;
(iv) lower amounts owing
for purchased power at
Newfoundland Power,
associated with seasonality
of operations; and (v)
timing of payments for
trade accounts payable at
the FortisBC Energy
companies. The decrease was
partially offset by an
increase in income and
other taxes payable at the
FortisBC Energy companies.
----------------------------------------------------------------------------
Regulatory 155 39 The increase was mainly due
liabilities - to: (i) a higher AESO
current and charges deferral at
long-term FortisAlberta; (ii) an
increase in non-ARO site
removal cost provisions,
primarily at FortisAlberta
and the FortisBC Energy
companies; and (iii) an
increase in rate
stabilization accounts at
the FortisBC Energy
companies.
----------------------------------------------------------------------------
Deferred income 279 40 The increase was driven by
tax liabilities tax timing differences
- current and related mainly to capital
long-term expenditures at the
regulated utilities.
----------------------------------------------------------------------------
Long-term debt 544 742 The increase was driven by
(including higher committed credit
current facility borrowings at the
portion) Corporation to finance a
portion of the acquisition
of CH Energy Group,
advances to the Waneta
Expansion Limited
Partnership ("Waneta
Partnership"), and an
equity injection into
FortisAlberta in support of
energy infrastructure
investment. Higher
committed credit facility
borrowings at the regulated
utilities were largely in
support of energy
infrastructure investment,
including the acquisition
of the City of Kelowna's
electrical utility assets
by FortisBC Electric. In
addition, Caribbean
Utilities issued US$50
million in senior unsecured
debentures in May 2013 to
repay short-term borrowings
and to finance capital
expenditures. The
translation of US-dollar
denominated debt also
resulted in an increase for
the period. The above-noted
increases were partially
offset by regularly
scheduled debt repayments
at the FortisBC Energy
companies and Fortis
Properties.
----------------------------------------------------------------------------
Other 185 (12) The decrease in other
Liabilities liabilities was not
significant.
----------------------------------------------------------------------------
Shareholders' - 707 The increase primarily
equity (before related to: (i) the
non-controlling conversion of Subscription
interests) Receipts into common shares
for $567 million, net of
after-tax expenses, in June
2013, to finance a portion
of the acquisition of CH
Energy Group; (ii) net
earnings attributable to
common equity shareholders
for the six months ended
June 30, 2013, less
dividends declared on
common shares; and (iii)
the issuance of common
shares under the
Corporation's Dividend
Reinvestment Plan.
----------------------------------------------------------------------------
Non-controlling - 46 The increase was driven by
interests advances from the 49% non-
controlling interests in
the Waneta Partnership.
----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the
three and six months ended June 30, 2013, as compared to the same periods in
2012, followed by a discussion of the nature of the variances in cash flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of Period 168 110 58 154 87 67
Cash Provided by (Used
in):
Operating Activities 291 255 36 571 583 (12)
Investing Activities (1,289) (273) (1,016) (1,578) (484) (1,094)
Financing Activities 1,097 139 958 1,120 45 1,075
----------------------------------------------------------------------------
Cash, End of Period 267 231 36 267 231 36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities was $36 million
higher quarter over quarter. The increase was primarily due to: (i) cash
proceeds received, in the second quarter of 2013, as a result of the March 2013
settlement of the expropriation of the non-regulated hydroelectric generating
assets and water rights of the Exploits Partnership; and (ii) favourable changes
in working capital associated with accounts payable and other current
liabilities.
Cash flow from operating activities was $12 million lower year to date compared
to the same period last year. The decrease was mainly due to unfavourable
changes in working capital, primarily at FortisAlberta and the FortisBC Energy
companies, partially offset by favourable changes in working capital at Maritime
Electric. The decrease was partially offset by: (i) cash proceeds received, in
the second quarter of 2013, as a result of the March 2013 settlement of
expropriation matters of the Exploits Partnership; and (ii) the collection from
customers of regulator-approved increases in depreciation and amortization
expense.
Investing Activities: Cash used in investing activities was $1,016 million
higher for the quarter and $1,094 million higher year to date compared to the
same periods last year. The increases were primarily due to the acquisition of
CH Energy Group on June 27, 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 spending at FortisAlberta and the FortisBC Energy companies for
the quarter and year to date was partially offset by lower capital spending
related to the non-regulated Waneta Expansion.
Financing Activities: Cash provided by financing activities was $958 million
higher for the quarter and $1,075 million higher year to date compared to the
same periods last year. The increases were 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.
Net repayments of short-term borrowings were $35 million higher quarter over
quarter, driven by Caribbean Utilities, partially offset by the FortisBC Energy
companies.
In May 2013 Caribbean Utilities issued 15-year US$10 million 3.34% and 20-year
US$40 million 3.54% senior unsecured notes. The proceeds were used to repay
short-term borrowings and to finance capital expenditures.
Repayments of long-term debt and capital lease and finance obligations and net
borrowings under committed credit facilities for the quarter and year to date
compared to the same periods last year are summarized in the following tables.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy Companies (5) (17) 12 (26) (18) (8)
Caribbean Utilities (17) (13) (4) (17) (13) (4)
Fortis Properties (2) (22) 20 (20) (24) 4
Other (1) (1) - (2) (2) -
----------------------------------------------------------------------------
Total (25) (53) 28 (65) (57) (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2013 2012 Variance 2013 2012 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta 46 38 8 94 9 85
FortisBC Electric 1 17 (16) 33 8 25
Newfoundland Power 1 14 (13) 22 28 (6)
Corporate 514 154 360 549 185 364
----------------------------------------------------------------------------
Total 562 223 339 698 230 468
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 of approximately $20 million during the quarter and $42 million year to
date were received from non-controlling interests in the Waneta Partnership to
finance capital spending related to the Waneta Expansion, compared to $27
million received during the second quarter of 2012 and $56 million received
year-to-date 2012. 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 $575 million higher for the
quarter and $583 million higher year to date compared to the same periods in
2012. The increases were primarily due to the issuance of 18.5 million common
shares, 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. Higher proceeds from the issuance of common shares for
the quarter and year to date also reflected a higher number of common shares
issued under the Corporation's stock option and employee share purchase plans.
Common share dividends paid during the second quarter of 2013 were $44 million,
net of $15 million of dividends reinvested, compared to $42 million, net of $15
million of dividends reinvested, paid during the same quarter of 2012. Common
share dividends paid in the first half of 2013 were $85 million, net of $34
million in dividends reinvested, compared to $86 million, net of $28 million in
dividends reinvested, paid in the first half of 2012. The dividend paid per
common share for the first and second quarters of 2013 was $0.31 compared to
$0.30 for the first and second quarters of 2012. The weighted average number of
common shares outstanding for the second quarter and year to date was 193.4
million and 192.7 million, respectively, compared to 189.6 million and 189.3
million, respectively, for the same periods in 2012.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third
parties in each of the next five years and for periods thereafter, as at June
30, 2013, are outlined in the following table. A detailed description of the
nature of the obligations is provided in the 2012 Annual MD&A and below, where
applicable.
----------------------------------------------------------------------------
Contractual
Obligations
(Unaudited) Due Due
As at June 30, 2013 within Due in Due in Due in Due in after
($ millions) Total 1 year year 2 year 3 year 4 year 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 7,186 201 699 836 329 80 5,041
Government loan
obligations 15 - 10 5 - - -
Capital lease and
finance obligations 2,569 48 49 50 51 51 2,320
Interest obligations
on long-term debt 6,996 375 351 337 310 295 5,328
Gas purchase
contract
obligations (1) 326 217 55 19 10 6 19
Power purchase
obligations:
Central Hudson (2) 50 25 5 3 3 3 11
FortisBC Electric 26 9 7 6 3 1 -
FortisOntario 334 46 50 51 52 53 82
Maritime Electric 121 38 41 27 1 1 13
Capital cost (3) 492 12 18 18 18 17 409
Construction and
maintenance
projects (4) 145 49 48 29 6 5 8
Operating lease
obligations 37 7 6 6 5 5 8
Waneta Partnership
promissory note 72 - - - - - 72
Joint-use asset and
shared service
agreements 62 4 3 3 3 3 46
Defined benefit
pension funding
contributions 66 29 15 12 6 1 3
Performance Share
Unit Plan
obligations 8 1 2 5 - - -
Other 12 8 1 - - - 3
----------------------------------------------------------------------------
Total 18,517 1,069 1,360 1,407 797 521 13,363
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Gas purchase contract obligations at the FortisBC Energy companies are
based on index prices as at June 30, 2013. Gas purchase contracts at
Central Hudson are predominantly for long-term storage and interstate
gas transportation contracts and are based on tariff rates as at June
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. In the event the counterparty is unable to fulfill
the commitment to deliver under the terms of the agreement, Central
Hudson would obtain required supply from the NYISO market, with cost
recovery from customers. Central Hudson must also acquire sufficient
peak load capacity to meet the peak load requirements of its full-
service customers. This capacity is made up of contracts with capacity
providers, purchases from the NYISO capacity market and its 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 $46
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. Certain of these
commitments are related to capital projects and are also included in
Central Hudson's capital expenditure forecast.
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 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 expires 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. 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 40%
equity, including preference shares, and 60% debt, as well as investment-grade
credit ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in each of
the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
June 30, 2013 December 31, 2012
($ millions) (%) ($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
and finance obligations
(net of cash) (1) 7,452 56.2 6,317 55.3
Preference shares 1,108 8.4 1,108 9.7
Common shareholders' equity 4,699 35.4 3,992 35.0
----------------------------------------------------------------------------
Total (2) 13,259 100.0 11,417 100.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes long-term debt and capital lease and finance obligations,
including current portion, and short-term borrowings, net of cash
(2) 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 an
increase in total debt, mainly in support of energy infrastructure investment,
net earnings attributable to common equity shareholders for the six months ended
June 30, 2013, less dividends declared on common shares, and 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 June 30, 2013 was 54.7% debt, 8.7% preference shares and 36.6%
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
plans for 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 $548 million in gross consolidated capital expenditures by
segment for the first half of 2013 is provided in the following table.
------------------------------------------------------------
Gross Consolidated Capital
Expenditures (Unaudited) (1)
Year-to-Date
June 30, 2013
($ millions)
------------------------------------------------------------
------------------------------------------------------------
Other
Regulated
FortisBC Electric
Energy Fortis FortisBC Newfoundland Utilities -
Companies Alberta Electric Power Canadian
----------------------------------------------------------------------------
92 230 33 38 28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Regulated Non- Non-
Regulated Electric Regulated - Regulated -
Utilities - Utilities - Fortis Non-
Canadian Caribbean Generation Utility Total
----------------------------------------------------------------------------
421 24 79 24 548
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital
assets, income producing properties 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 at approximately
$1.3 billion. There have been no material changes in the overall expected level,
nature and timing of the Corporation's significant capital projects from those
that were disclosed in the 2012 Annual MD&A, with the exception of those noted
below for the Waneta Expansion, FAES and Central Hudson.
Capital expenditures related to the Waneta Expansion for 2013 are expected to be
lower than the original forecast of $227 million, primarily due to the timing of
payments. Due to the uncertainty of the timing of alternative energy projects,
capital expenditures for 2013 at FAES are delayed and are expected to be lower
than the original forecast of $43 million. Capital expenditures for 2013 now
include approximately $50 million in capital spending forecast at Central Hudson
for the second half of 2013.
Construction of the $900 million Waneta Expansion is ongoing, with an additional
$77 million invested in the first half of 2013. To date, approximately $513
million has been invested in the Waneta Expansion since construction began late
in 2010. Key construction activities in the first half of 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 substantial completion of the intake
channel excavation. The key offsite activity in the first half of 2013 was the
successful completion of the factory acceptance testing of the generator step-up
transformers.
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: 55% at
Canadian Regulated Electric Utilities, driven by FortisAlberta; 20% at Canadian
Regulated Gas Utilities; 11% at Central Hudson; 4% at Caribbean Regulated
Electric Utilities; and the remaining 10% 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 June 30, 2013, management expects consolidated long-term debt maturities
and repayments to average approximately $310 million annually over the next five
years, excluding borrowings under the Corporation's committed credit facility
which are expected to be 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 "Subsequent
Events" section in this MD&A). The remaining room 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.
Fortis and its subsidiaries were compliant with debt covenants as at June 30,
2013 and are expected to remain compliant throughout 2013.
CREDIT FACILITIES
As at June 30, 2013, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.7 billion, of which $1.7 billion was
unused, including $395 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 $2.6 billion of the
total credit facilities are committed facilities with maturities ranging from
2013 through 2018.
The following summary outlines the credit facilities of the Corporation and its
subsidiaries.
----------------------------------------------------------------------------
Credit Facilities (Unaudited) As at
December
Regulated Non- Corporate June 30, 31,
($ millions) Utilities Regulated and Other 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit
facilities 1,560 112 1,030 2,702 2,460
Credit facilities
utilized:
Short-term
borrowings (72) (27) - (99) (136)
Long-term debt
(including current
portion) (226) - (603) (829) (150)
Letters of credit
outstanding (66) - (2) (68) (67)
----------------------------------------------------------------------------
Credit facilities
unused 1,196 85 425 1,706 2,107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 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$31 million ($33 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 ($13 million), a capital
expenditure line of credit of US$10 million ($11 million) and a US$9 million ($9
million) emergency standby loan. The capital expenditure line of credit matures
in December 2013. The remaining facilities mature in June 2014. The new credit
facilities reflect a decrease in pricing but otherwise contain terms and
conditions substantially similar to the previous facilities.
As at June 30, 2013, CH Energy Group had a US$100 million ($105 million)
unsecured revolving credit facility maturing in October 2015, and Central Hudson
had a US$150 million ($158 million) unsecured committed revolving credit
facility maturing in October 2016.
In July 2013 FEI, FEVI and FortisAlberta amended their $500 million, $200
million and $250 million committed revolving credit facilities, resulting in
extensions to the maturity dates to August 2015, December 2015 and August 2018,
respectively, from August 2014, December 2013 and August 2016, respectively. The
new agreements contain substantially similar terms and conditions as the
previous credit facility agreements.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows.
----------------------------------------------------------------------------
Financial Instruments
(Unaudited) As at
June 30, 2013 December 31, 2012
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Waneta Partnership
promissory note 48 50 47 51
Long-term debt,
including current
portion 7,186 8,220 5,900 7,338
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $109 million as at June 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 June 30, 2013, the Corporation's corporately issued US$1,052 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 June 30,
2013, the Corporation had approximately US$534 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 June 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 gain of approximately $3
million and $5 million, for the three and six months ended June 30, 2013,
respectively ($2 million and $0.5 million for the three and six months ended
June 30, 2012, respectively).
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel, electricity and
natural gas prices through the use of derivative instruments. The Corporation
and its subsidiaries do not hold or issue derivative instruments for trading
purposes. As at June 30, 2013, the Corporation's derivative contracts consisted
of fuel option contracts, electricity swap contracts, natural gas swap and
option contracts, and gas purchase contract premiums. The fuel option contracts
are held by Caribbean Utilities. Electricity swap contracts are held by Central
Hudson. Gas swaps and options and gas purchase contract premiums are held by the
FortisBC Energy companies and Central Hudson.
The following table summarizes the Corporation's derivative instruments.
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Derivative Instruments (Unaudited) As at
December
June 30, 31,
2013 2012
Carrying Carrying
Value (2) Value (2)
Number of ($ ($
Liability Maturity Contracts Volume (1) millions) millions)
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Fuel option
contracts (3) 2013 2 4 - (1)
Electricity swap
contracts 2017 9 2,625 (1) -
Natural gas
commodity
derivatives:
Gas swaps and
options 2014 42 15 (31) (51)
Gas purchase
contract
premiums 2015 44 78 (2) (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 represents the
gross derivatives balance.
(3) The carrying value of the fuel option contracts was less than $1
million as at June 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 fuel option
contracts mature 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 natural gas commodity derivatives held by the FortisBC Energy companies are
used to fix the effective purchase price of natural gas, as the majority of the
natural gas supply contracts at the FortisBC Energy companies have floating,
rather than fixed, prices. The price risk-management strategy of the FortisBC
Energy companies aims to improve the likelihood that natural gas prices remain
competitive, 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 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 June 30,
2013 and December 31, 2012.
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 fair
values of the electricity swap contracts and natural gas commodity derivatives
were calculated using forward pricing provided by independent third parties. 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.
The fair values of the Corporation's financial instruments, including
derivatives, reflect point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $68 million as at June
30, 2013 (December 31, 2012 - $67 million), the Corporation had no off-balance
sheet arrangements, such as transactions, agreements or contractual arrangements
with unconsolidated entities, structured finance entities, special purpose
entities or variable interest entities, that are reasonably likely to materially
affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
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 second half 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 of the expropriated investment was approximately $109 million,
including foreign exchange impacts, as at June 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 $109 million long-term other asset is not deemed
impaired as at June 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 July 31, 2013, Belize Electricity owed BECOL US$3
million for overdue energy purchases, representing approximately 15% 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 June 30, 2013, the fair
value of the Corporation's consolidated defined benefit pension and OPEB plan
assets was $1,545 million, up $677 million or 78%, from $868 million as at
December 31, 2012. Of the increase from December 31, 2012, approximately $656
million, or 97% was due to the acquisition of CH Energy Group.
Labour Relations: The collective agreement between employees in specified
occupations in the areas of administration and operations support at the
FortisBC Energy companies and the Canadian Office and Professional Employees
Union, Local 378, expired on March 31, 2012. 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 unsuccessful in collective
bargaining efforts to date. As a result, FortisBC Electric activated the
essential services order issued in April 2013 by the Labour Relations Board of
British Columbia. The IBEW is complying with the order and the Company continues
to deliver safe and reliable electricity to its customers and 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.
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 amended disclosures are intended to assist financial statement users in
understanding significant quantitative differences between balance sheets
prepared under US GAAP and International Financial Reporting Standards. ASU No.
2013-01 limits the scope of the new offsetting disclosure requirements
previously issued in ASU No. 2011-11 to certain derivative instruments,
repurchase and reverse repurchase agreements, and securities borrowing and
lending arrangements that are either offset on the balance sheet or subject to
an enforceable master netting or similar arrangement. The above-noted amendments
were applied retrospectively and did not materially impact the Corporation's
interim consolidated financial statements for the three and six months ended
June 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 effect of the reclassification of significant items to net income
in their entirety during the reporting period must be reported in the respective
line items in the statement where net income is presented. The effect of items
not reclassified to net income in their entirety during the reporting period are
to be presented in the notes to the consolidated financial statements. 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 six months ended June 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.
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. Certain amounts are 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 1800s with all sites ceasing operations by
the 1950s. 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
June 30, 2013, an obligation of US$9 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 3,340 asbestos cases have been
raised, 1,168 remained pending as at June 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 September 30, 2011 through June 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.
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Summary of Quarterly Results
(Unaudited)
Net Earnings
Attributable
to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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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
September 30, 2011 699 56 0.30 0.30
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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.
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. A discussion of the quarter over quarter variance in financial
results is provided in the "Financial Highlights" section of this MD&A.
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 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 transportation
volumes to industrial customers, 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 to industrial
customers and lower effective income taxes.
September 2012/September 2011: Net earnings attributable to common equity
shareholders were $45 million, or $0.24 per common share, for the third quarter
of 2012 compared to earnings of $56 million, or $0.30 per common share, for the
third quarter of 2011. Earnings for the third quarter of 2012 were reduced by
$3.5 million related to foreign exchange and CH Energy Group acquisition-related
expenses. Earnings for the third quarter of 2011 were favourably impacted by a
one-time $11 million after-tax merger termination fee paid to Fortis by Central
Vermont Public Service Corporation and $2.5 million of foreign exchange.
Excluding the above impacts, higher earnings at FortisAlberta and FortisBC
Electric for the quarter were partially offset by decreased non-regulated
hydroelectric generation in Belize, due to lower rainfall, and a higher loss
incurred at the FortisBC Energy companies. The improved performance at
FortisAlberta was due to net transmission revenue of $3.5 million recognized in
the third quarter of 2012, rate base growth and the timing of operating expenses
during 2012, partially offset by a lower allowed ROE. At FortisBC Electric,
improved performance was driven by rate base growth, higher pole-attachment
revenue and lower-than-expected finance charges. The higher loss at the FortisBC
Energy companies related to the unfavourable impact of the difference in the
timing of recognition of revenue associated with seasonal gas consumption and
certain increased regulator-approved expenses in 2012, lower capitalized AFUDC
and lower-than-expected customer additions in 2012. The above items were
partially offset by higher gas transportation volumes to industrial customers
and the timing of certain operating and maintenance expenses during 2012.
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 non-regulated 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 EVENTS
On July 10, 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.
On July 18, 2013, the Corporation issued 10 million Cumulative Redeemable Fixed
Rate Reset First Preference Shares, Series K at $25.00 per share for gross
proceeds of $250 million. The net proceeds of the offering were used to repay a
portion of borrowings under the Corporation's $1 billion committed corporate
credit facility, including amounts borrowed in connection with the above-noted
redemption of the Corporation's First Preference Shares, Series C, the
construction of the Waneta Expansion and equity injections into certain of the
Corporation's subsidiaries, and for general corporate purposes.
On July 19, 2013, the Corporation priced 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 offering is scheduled to close on October 1, 2013. Proceeds from the
offering will be used to repay a portion of the Corporation's US
dollar-denominated committed credit facility borrowings incurred to initially
finance a portion of the CH Energy Group acquisition.
On July 26, 2013, applications for rehearing of the approval of the CH Energy
Group acquisition were filed with the PSC. In addition, the parties petitioned
the PSC to designate Central Hudson's rates as temporary pending further review
of certain matters, including the Company's allowed ROE. The Corporation is
preparing a response to the applications, which it expects to file shortly.
OUTSTANDING SHARE DATA
As at July 31, 2013, the Corporation had issued and outstanding approximately
211.7 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 July
31, 2013 is as follows.
----------------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at July 31, 2013 Number of
Common Shares
Security (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options 5.2
First Preference Shares, Series E 6.5
----------------------------------------------------------------------------
Total 11.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 six months ended June 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)
June 30, December 31,
2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 24)
ASSETS
Current assets
Cash and cash equivalents $ 267 $ 154
Accounts receivable 591 587
Prepaid expenses 33 18
Inventories 138 133
Regulatory assets (Note 4) 178 185
Deferred income taxes 30 16
--------------------------------
1,237 1,093
Other assets 238 200
Regulatory assets (Note 4) 1,790 1,515
Deferred income taxes 7 -
Utility capital assets 11,272 9,623
Non-utility capital assets 651 626
Intangible assets 361 325
Goodwill (Note 14) 2,077 1,568
--------------------------------
$ 17,633 $ 14,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 19) $ 99 $ 136
Accounts payable and other current
liabilities 962 966
Regulatory liabilities (Note 4) 114 72
Current installments of long-term debt 201 159
Current installments of capital lease and
finance obligations 7 7
Deferred income taxes 10 10
--------------------------------
1,393 1,350
Other liabilities 811 638
Regulatory liabilities (Note 4) 833 681
Deferred income taxes 1,021 702
Long-term debt 6,985 5,741
Capital lease and finance obligations 427 428
--------------------------------
11,470 9,540
--------------------------------
Shareholders' equity
Common shares (1)(Note 5) 3,739 3,121
Preference shares 1,108 1,108
Additional paid-in capital 16 15
Accumulated other comprehensive loss (88) (96)
Retained earnings 1,032 952
--------------------------------
5,807 5,100
Non-controlling interests (Note 6) 356 310
--------------------------------
6,163 5,410
--------------------------------
$ 17,633 $ 14,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) No par value. Unlimited authorized shares; 211.7 million and 191.6
million issued and outstanding as at June 30, 2013 and December 31,
2012, respectively
Commitments and Contingent Liabilities (Notes 20 and 22, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
2013 2012 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 790 $ 792 $ 1,903 $ 1,941
---------------------------------------
Expenses
Energy supply costs 282 291 787 857
Operating 206 204 427 418
Depreciation and amortization 130 114 259 233
---------------------------------------
618 609 1,473 1,508
---------------------------------------
Operating income 172 183 430 433
Other income (expenses), net (Note 9) (44) - (38) (3)
Finance charges (Note 10) 92 92 181 183
---------------------------------------
Earnings before income taxes and
extraordinary item 36 91 211 247
Income tax (recovery) expense (Note
11) (34) 14 (4) 37
---------------------------------------
Earnings before extraordinary item 70 77 215 210
Extraordinary gain, net of tax (Note
12) - - 22 -
---------------------------------------
Net earnings $ 70 $ 77 $ 237 $ 210
---------------------------------------
---------------------------------------
Net earnings attributable to:
Non-controlling interests $ 2 $ 3 $ 4 $ 4
Preference equity shareholders 14 12 28 23
Common equity shareholders 54 62 205 183
---------------------------------------
$ 70 $ 77 $ 237 $ 210
---------------------------------------
---------------------------------------
Earnings per common share
before extraordinary item (Note 13)
Basic $ 0.28 $ 0.33 $ 0.95 $ 0.97
Diluted $ 0.28 $ 0.33 $ 0.94 $ 0.95
Earnings per common share (Note 13)
Basic $ 0.28 $ 0.33 $ 1.06 $ 0.97
Diluted $ 0.28 $ 0.33 $ 1.05 $ 0.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2013 2012 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 70 $ 77 $ 237 $ 210
----------------------------------------
----------------------------------------
Other comprehensive income
Unrealized foreign currency
translation gains, net of hedging
activities and tax 5 2 7 -
Unrealized employee future benefits
gains, net of tax - - 1 1
----------------------------------------
5 2 8 1
----------------------------------------
Comprehensive income $ 75 $ 79 $ 245 $ 211
----------------------------------------
----------------------------------------
Comprehensive income attributable
to:
Non-controlling interests $ 2 $ 3 $ 4 $ 4
Preference equity shareholders 14 12 28 23
Common equity shareholders 59 64 213 184
----------------------------------------
$ 75 $ 79 $ 245 $ 211
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2013 2012 2013 2012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 70 $ 77 $ 237 $ 210
Adjustments to reconcile net
earnings to net cash
provided by operating activities:
Depreciation - capital assets 115 94 228 201
Amortization - intangible assets 11 10 23 21
Amortization - other 4 10 8 11
Deferred income tax (recovery)
expense (11) 3 (22) 8
Accrued employee future benefits (4) (11) (5) (7)
Equity component of allowance for
funds used during construction
(Note 9) (1) (1) (4) (3)
Other (13) 3 (23) (11)
Change in long-term regulatory
assets and liabilities - (13) (9) (9)
Change in non-cash operating working
capital (Note 16) 120 83 138 162
----------------------------------------
291 255 571 583
----------------------------------------
Investing activities
Change in other assets and other
liabilities (11) - (6) 4
Capital expenditures - utility
capital assets (278) (262) (508) (473)
Capital expenditures - non-utility
capital assets (11) (10) (24) (15)
Capital expenditures - intangible
assets (9) (10) (16) (23)
Contributions in aid of construction 20 16 30 30
Proceeds on sale of capital assets - - 1 -
Business acquisitions, net of cash
acquired (Note 14) (1,000) (7) (1,055) (7)
----------------------------------------
(1,289) (273) (1,578) (484)
----------------------------------------
Financing activities
Change in short-term borrowings (30) 5 (78) (78)
Proceeds from long-term debt, net of
issue costs 51 - 51 -
Repayments of long-term debt and
capital lease and finance
obligations (25) (53) (65) (57)
Net borrowings under committed
credit facilities 562 223 698 230
Advances from non-controlling
interests 21 28 43 69
Subscription Receipts issue costs
(Note 5) - (12) - (12)
Issue of common shares, net of costs
and dividends reinvested (Note 5) 579 4 589 6
Dividends
Common shares, net of dividends
reinvested (44) (42) (85) (86)
Preference shares (14) (12) (28) (23)
Subsidiary dividends paid to non-
controlling interests (3) (2) (5) (4)
----------------------------------------
1,097 139 1,120 45
----------------------------------------
Change in cash and cash equivalents 99 121 113 144
Cash and cash equivalents, beginning
of period 168 110 154 87
----------------------------------------
Cash and cash equivalents, end of
period $ 267 $ 231 $ 267 $ 231
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note 16)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Accumulated
Additional Other
Common Preference Paid-in Comprehensive
Shares Shares Capital Loss
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 5)
As at January 1, 2013 $ 3,121 $ 1,108 $ 15 $ (96)
Net earnings - - - -
Other comprehensive
income - - - 8
Common share issues 618 - (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 ($0.62 per
share) - - - -
Dividends declared on
preference shares - - - -
---------------------------------------------------
As at June 30, 2013 $ 3,739 $ 1,108 $ 16 $ (88)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at January 1, 2012 $ 3,036 $ 912 $ 14 $ (95)
Net earnings - - - -
Other comprehensive
income - - - 1
Common share issues 35 - - -
Stock-based compensation - - 1 -
Advances from non-
controlling interests - - - -
Foreign currency
translation impacts - - - -
Subsidiary dividends paid
to non-controlling
interests - - - -
Dividends declared on
common shares ($0.60 per
share) - - - -
Dividends declared on
preference shares - - - -
---------------------------------------------------
As at June 30, 2012 $ 3,071 $ 912 $ 15 $ (94)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained Non-Controlling Total
Earnings Interests Equity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at January 1, 2013 $ 952 $ 310 $ 5,410
Net earnings 233 4 237
Other comprehensive
income - - 8
Common share issues - - 617
Stock-based compensation - - 2
Advances from non-
controlling interests - 43 43
Foreign currency
translation impacts - 4 4
Subsidiary dividends paid
to non-controlling
interests - (5) (5)
Dividends declared on
common shares ($0.62 per
share) (125) - (125)
Dividends declared on
preference shares (28) - (28)
---------------------------------------------------
As at June 30, 2013 $ 1,032 $ 356 $ 6,163
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at January 1, 2012 $ 868 $ 208 $ 4,943
Net earnings 206 4 210
Other comprehensive
income - - 1
Common share issues - - 35
Stock-based compensation - - 1
Advances from non-
controlling interests - 69 69
Foreign currency
translation impacts - (2) (2)
Subsidiary dividends paid
to non-controlling
interests - (4) (4)
Dividends declared on
common shares ($0.60 per
share) (114) - (114)
Dividends declared on
preference shares (23) - (23)
---------------------------------------------------
As at June 30, 2012 $ 937 $ 275 $ 5,116
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 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. The
Corporation's reporting segments allow senior management to evaluate the
operational performance and assess the overall contribution of each segment to
the long-term objectives of Fortis. Each 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
14).
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 14).
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 Exploits River Hydro Partnership
("Exploits Partnership") in which Fortis held an indirect 51% interest (Note
12).
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 14). Griffith supplies petroleum products and related
services to approximately 56,000 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
reported in earnings in the period in which they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the three and six months
ended June 30, 2013.
An evaluation of subsequent events through to July 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 June 30, 2013 (Note 23).
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. Other than expenses associated with customer and
community benefits offered by the Corporation to close the acquisition of CH
Energy Group, which are reported in the Corporate and Other segment, financial
performance for CH Energy Group from the date of acquisition through June 30,
2013 did not have a material impact on the Corporation's consolidated statement
of earnings. 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
related to regulation at Central Hudson.
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 provides for the use of a future test year in the
establishment 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 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 14). Effective July 1, 2013, Central Hudson is
also subject to a modified earnings sharing mechanism, whereby the Company and
customers share equally 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 also 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 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 amended disclosures are intended to assist financial
statement users in understanding significant quantitative differences between
balance sheets prepared under US GAAP and International Financial Reporting
Standards. ASU No. 2013-01 limits the scope of the new offsetting disclosure
requirements previously issued in ASU No. 2011-11 to certain derivative
instruments, repurchase and reverse repurchase agreements, and securities
borrowing and lending arrangements that are either offset on the balance sheet
or subject to an enforceable master netting or similar arrangement. The
above-noted amendments were applied retrospectively and did not materially
impact the Corporation's interim consolidated financial statements for the three
and six months ended June 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 effect of the reclassification of significant
items to net income in their entirety during the reporting period must be
reported in the respective line items in the statement where net income is
presented. The effect of items not reclassified to net income in their entirety
during the reporting period are to be presented in the notes to the consolidated
financial statements. 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 six
months ended June 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.
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
June 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes (i) 786 713
Employee future benefits (i) 649 498
Deferred lease costs - FortisBC Electric 81 77
Rate stabilization accounts - electric
utilities (i) 70 57
Deferred energy management costs (i) 60 50
Rate stabilization accounts - gas utilities
(i) 45 48
Deferred operating overhead costs 38 32
Deferred net losses on disposal of utility
capital assets and intangible assets 34 27
Customer Care Enhancement Project cost
deferral 23 24
Income taxes recoverable on OPEB plans 23 23
Alternative energy projects cost deferral 14 18
MGP site remediation deferral (i) 14 -
Whistler pipeline contribution deferral 13 14
Deferred development costs for capital
projects 10 10
Residual natural gas deferral (i) 8 -
Deferred costs - smart meters 1 9
Replacement energy deferral - Point Lepreau
(ii) - 47
Other regulatory assets (i) 99 53
----------------------------------------------------------------------------
Total regulatory assets 1,968 1,700
Less: current portion (178) (185)
----------------------------------------------------------------------------
Long-term regulatory assets 1,790 1,515
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at
June 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Regulatory liabilities
Non-asset retirement obligation removal cost
provision (iii) 551 486
Rate stabilization accounts - gas utilities
(iii) 131 117
Alberta Electric System Operator charges
deferral 60 44
Rate stabilization accounts - electric
utilities (iii) 38 46
Deferred income taxes (iii) 33 12
OPEB cost deferral (iii) 25 -
Customer and community benefits obligation
(iii) 21 -
Meter reading and customer service variance
deferral 12 6
Rate base impact of tax repair project (iii) 10 -
Deferred interest 8 9
Income tax variance deferral 3 7
Other regulatory liabilities (iii) 55 26
----------------------------------------------------------------------------
Total regulatory liabilities 947 753
Less: current portion (114) (72)
----------------------------------------------------------------------------
Long-term regulatory liabilities 833 681
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Description of the Nature of Regulatory Assets and Liabilities
i. The respective regulatory assets as at June 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 June 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 14). These incremental benefits include: (i) US$35 million to
cover expenses that would normally be recovered in customer rates,
including certain storm-restoration expenses; (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$20 million) (Notes 9 and 14).
The tax-repair project regulatory liability represents accumulated tax
refunds plus accrued carrying charges to be refunded to customers
through future rates over a time period to be determined during Central
Hudson's next rate hearing with the PSC.
5. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
June 30, 2013 June 30, 2013
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning
of period 192,476 3,149 191,566 3,121
Public offering
- Conversion of
Subscription
Receipts 18,500 567 18,500 567
Dividend
Reinvestment
Plan 483 16 1,046 35
Consumer Share
Purchase Plan 8 1 17 1
Employee Share
Purchase Plan 71 2 217 7
Stock Option
Plans 179 4 371 8
----------------------------------------------------------------------------
Balance, end of
period 211,717 3,739 211,717 3,739
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In June 2012, to finance a portion of the acquisition of CH Energy Group, the
Corporation sold 18,500,000 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 $567
million, net of after-tax expenses.
6. NON-CONTROLLING INTERESTS
As at
June 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Waneta Expansion Limited Partnership
("Waneta Partnership") 262 220
Caribbean Utilities 75 71
Mount Hayes Limited Partnership 12 12
Preference shares of Newfoundland Power 7 7
----------------------------------------------------------------------------
356 310
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. 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.
For the three and six months ended June 30, 2013, stock-based compensation
expense of approximately $3 million and $4 million, respectively, was recognized
($1.5 million and $3 million for the three and six months ended June 30, 2012,
respectively).
8. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans and defined contribution pension plans, including
group registered retirement savings plans, for employees. The Corporation and
certain subsidiaries also offer OPEB plans for qualifying employees. The net
benefit cost of providing the defined benefit pension and OPEB plans is detailed
in the following tables.
Quarter Ended June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 8 7 2 1
Interest costs 11 11 3 3
Expected return on plan
assets (14) (13) - -
Amortization of actuarial
losses 7 7 1 1
Amortization of past service
credits/plan amendments - - (1) (1)
Amortization of transitional
obligation - 1 - 1
Regulatory adjustments (4) (5) 1 -
----------------------------------------------------------------------------
Net benefit cost 8 8 6 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Components of net benefit
cost:
Service costs 16 14 4 3
Interest costs 23 23 6 6
Expected return on plan
assets (27) (25) - -
Amortization of actuarial
losses 14 13 3 2
Amortization of past service
credits/plan amendments - - (2) (2)
Amortization of transitional
obligation - 1 - 1
Regulatory adjustments (7) (6) 1 1
----------------------------------------------------------------------------
Net benefit cost 19 20 12 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three and six months ended June 30, 2013, the Corporation expensed $3
million and $7 million, respectively ($3 million and $7 million for the three
and six months ended June 30, 2012 respectively), related to defined
contribution pension plans.
9. OTHER INCOME (EXPENSES), NET
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Equity component of
allowance for funds used
during construction
("AFUDC") 1 1 4 3
Net foreign exchange gain 3 2 5 -
Interest income 1 1 2 2
Acquisition-related expenses
(Note 14) (8) (4) (8) (8)
Acquisition-related customer
and community benefits
(Notes 4 and 14) (41) - (41) -
----------------------------------------------------------------------------
(44) - (38) (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net foreign exchange gain for the three and six months ended June 30, 2013
relates to approximately $3 million and $5 million, respectively ($2 million and
$0.5 million for the three and six months ended June 30, 2012, respectively),
associated with the translation into Canadian dollars of the Corporation's US
dollar-denominated long-term other asset representing the book value of the
Corporation's expropriated investment in Belize Electricity (Notes 19 and 21).
10. FINANCE CHARGES
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Interest:
Long-term debt and capital
lease and finance
obligations 94 93 188 187
Short-term borrowings 2 2 4 3
Debt component of AFUDC (4) (3) (11) (7)
----------------------------------------------------------------------------
92 92 181 183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. 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
June 30 June 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 10 26 61 72
Difference in Canadian provincial
statutory rates applicable to
subsidiaries in different
Canadian jurisdictions (2) (2) (8) (8)
Difference between Canadian
statutory rate and rates
applicable to foreign
subsidiaries (5) (5) (7) (7)
Items capitalized for accounting
purposes but expensed for income
tax purposes (10) (12) (26) (28)
Difference between capital cost
allowance and amounts claimed for
accounting purposes - 1 (2) 4
Non-deductible expenses 1 3 2 3
Impacts associated with Part VI.1
tax (25) 3 (23) 3
Difference between employee future
benefits paid and amounts
expensed for accounting purposes - 1 1 1
Other (3) (1) (2) (3)
----------------------------------------------------------------------------
Income tax (recovery) expense (34) 14 (4) 37
----------------------------------------------------------------------------
Effective income tax rate (94.4)% 15.4% (1.9)% 15.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 22).
As at June 30, 2013, the Corporation had non-capital and capital loss
carryforwards of approximately $87 million (December 31, 2012 - $73 million), of
which $13 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.
12. 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
Exploits Partnership, in which Fortis held an indirect 51% interest. As a result
of the settlement, an extraordinary gain of approximately $25 million ($22
million after tax) was recognized in the first quarter of 2013.
13. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding. Diluted EPS is calculated using the
treasury stock method for options and the "if-converted" method for convertible
securities.
Earnings
to Common
Shareholders
Before Earnings
Extraordinary Extraordinary to Common
Quarter Ended Item Gain Shareholders
June 30, 2013 ($ millions) ($ millions) ($ millions)
----------------------------------------------------------------------------
Basic EPS 54 - 54
Effect of potential
dilutive securities:
Stock Options - - -
Preference Shares 4 - 4
----------------------------------------------------------------------------
58 - 58
Deduct anti-dilutive
impacts:
Preference Shares (4) - (4)
----------------------------------------------------------------------------
Diluted EPS 54 - 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2012
----------------------------------------------------------------------------
Basic EPS 62 - 62
Effect of potential
dilutive securities:
Stock Options - - -
Preference Shares 4 - 4
----------------------------------------------------------------------------
66 - 66
Deduct anti-dilutive
impacts:
Preference Shares (4) - (4)
----------------------------------------------------------------------------
Diluted EPS 62 - 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted EPS
Average Before EPS
Quarter Ended Shares Extraordinary Extraordinary
June 30, 2013 (millions) Item Gain EPS
----------------------------------------------------------------------------
Basic EPS 193.4 $0.28 $- $ 0.28
Effect of potential
dilutive securities:
Stock Options 0.7
Preference Shares 10.0
----------------------------------------------------------------------------
204.1
Deduct anti-dilutive
impacts:
Preference Shares (10.0)
----------------------------------------------------------------------------
Diluted EPS 194.1 $0.28 $- $ 0.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2012
----------------------------------------------------------------------------
Basic EPS 189.6 $0.33 $- $ 0.33
Effect of potential
dilutive securities:
Stock Options 0.9
Preference Shares 10.3
----------------------------------------------------------------------------
200.8
Deduct anti-dilutive
impacts:
Preference Shares (10.3)
----------------------------------------------------------------------------
Diluted EPS 190.5 $ 0.33 $- $ 0.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings
to Common
Shareholders
Before Earnings
Extraordinary Extraordinary to Common
Year-to-Date Item Gain Shareholders
June 30, 2013 ($ millions) ($ millions) ($ millions)
----------------------------------------------------------------------------
Basic EPS 183 22 205
Effect of potential dilutive
securities:
Stock Options - - -
Preference Shares 8 - 8
----------------------------------------------------------------------------
Diluted EPS 191 22 213
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2012
----------------------------------------------------------------------------
Basic EPS 183 - 183
Effect of potential dilutive
securities:
Stock Options - - -
Preference Shares 8 - 8
----------------------------------------------------------------------------
Diluted EPS 191 - 191
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted EPS
Average Before EPS
Year-to-Date Shares Extraordinary Extraordinary
June 30, 2013 (millions) Item Gain EPS
----------------------------------------------------------------------------
Basic EPS 192.7 $0.95 $ 0.11 $1.06
Effect of potential dilutive
securities:
Stock Options 0.7
Preference Shares 10.0
----------------------------------------------------------------------------
Diluted EPS 203.4 $0.94 $ 0.11 $1.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2012
----------------------------------------------------------------------------
Basic EPS 189.3 $0.97 $- $0.97
Effect of potential dilutive
securities:
Stock Options 0.9
Preference Shares 10.3
----------------------------------------------------------------------------
Diluted EPS 200.5 $0.95 $- $0.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
14. 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 300,000 electric and 77,000 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. Other than
acquisition-related expenses noted below, financial performance for CH Energy
Group from the date of acquisition through June 30, 2013 did not have a material
impact on the Corporation's consolidated statement of earnings.
Acquisition-related expenses totalled approximately $8 million ($6 million after
tax) for the three and six months ended June 30, 2013 and have been recognized
in other income (expenses), net on the consolidated statement of earnings (Note
9). In addition, approximately $41 million (US$40 million), or $26 million
(US$26 million after tax), in customer and community benefits offered to obtain
regulatory approval of the acquisition were expensed in the second quarter of
2013, as approved by the PSC, and were also recognized in other income
(expenses), net on the consolidated statement of earnings (Notes 4 and 9).
Supplemental Pro Forma Data
The unaudited pro forma financial information below gives effect to the
acquisition of CH Energy Group as if the transaction had occurred at the
beginning of 2012. This pro forma data is presented for information purposes
only, and does not necessarily represent the results that would have occurred
had the acquisition taken place at the beginning of 2012, nor is it necessarily
indicative of the results that may be expected in future periods.
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Pro forma revenue 1,005 992 2,420 2,415
Pro forma net earnings (1) 106 82 290 258
----------------------------------------------------------------------------
(1) Pro forma net earnings exclude all acquisition-related expenses
incurred by CH Energy Group and the Corporation, net of tax (Note 9). 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.
15. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED UTILITIES
---------------------------------------------------------------
Gas &
GasElectric Electric
---------------------------------------------------------------
Fortis-
BC Fortis- New- Total
Quarter Ended Energy Central BC found- Other Electric Electric
June 30, 2013 Cana- Hudson Fortis Elec- land Cana- Cana- Carib-
($ millions) dian US Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 246 - 117 68 132 87 404 70
Energy supply
costs 90 - - 14 80 56 150 43
Operating
expenses 65 - 38 22 16 12 88 8
Depreciation
and
amortization 46 - 36 12 13 7 68 9
----------------------------------------------------------------------------
Operating
income 45 - 43 20 23 12 98 10
Other income
(expenses),
net - - - 1 - - 1 1
Finance
charges 36 - 18 10 9 5 42 3
Income tax
expense
(recovery) 3 - - 3 (10) (2) (9) -
----------------------------------------------------------------------------
Net earnings
(loss) 6 - 25 8 24 9 66 8
Non-
controlling
interests - - - - - - - 2
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 6 - 25 8 24 9 66 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 486 227 235 - 67 529 149
Identifiable
assets 4,528 1,763 2,927 1,748 1,394 691 6,760 680
----------------------------------------------------------------------------
Total assets 5,441 2,249 3,154 1,983 1,394 758 7,289 829
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 54 - 135 16 23 15 189 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2012
($ millions)
----------------------------------------------------------------------------
Revenue 264 - 110 67 130 82 389 67
Energy supply
costs 109 - - 13 79 51 143 39
Operating
expenses 63 - 37 21 17 12 87 9
Depreciation
and
amortization 40 - 30 12 11 6 59 9
----------------------------------------------------------------------------
Operating
income 52 - 43 21 23 13 100 10
Other income
(expenses),
net 1 - - - 1 - 1 1
Finance
charges 36 - 17 10 9 6 42 3
Income tax
expense
(recovery) 3 - - 2 4 2 8 -
----------------------------------------------------------------------------
Net earnings
(loss) 14 - 26 9 11 5 51 8
Non-
controlling
interests 1 - - - - - - 2
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 13 - 26 9 11 5 51 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 - 227 221 - 67 515 142
Identifiable
assets 4,566 - 2,575 1,671 1,298 692 6,236 631
----------------------------------------------------------------------------
Total assets 5,479 - 2,802 1,892 1,298 759 6,751 773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 32 - 121 16 21 13 171 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
--------------------------------------
Quarter Ended Inter-
June 30, 2013 Fortis Non- Corporate segment
($ millions) Generation Utility and Other eliminations Total
----------------------------------------------------------------------------
Revenue 7 65 7 (9) 790
Energy supply
costs - - - (1) 282
Operating
expenses 3 41 3 (2) 206
Depreciation
and
amortization 1 6 - - 130
----------------------------------------------------------------------------
Operating
income 3 18 4 (6) 172
Other income
(expenses),
net - - (46) - (44)
Finance
charges - 6 11 (6) 92
Income tax
expense
(recovery) - 3 (31) - (34)
----------------------------------------------------------------------------
Net earnings
(loss) 3 9 (22) - 70
Non-
controlling
interests - - - - 2
Preference
share
dividends - - 14 - 14
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 3 9 (36) - 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 2,077
Identifiable
assets 832 808 643 (458) 15,556
----------------------------------------------------------------------------
Total assets 832 808 643 (458) 17,633
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 31 11 - - 298
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2012
($ millions)
----------------------------------------------------------------------------
Revenue 9 64 7 (8) 792
Energy supply
costs - - - - 291
Operating
expenses 1 42 3 (1) 204
Depreciation
and
amortization 1 5 - - 114
----------------------------------------------------------------------------
Operating
income 7 17 4 (7) 183
Other income
(expenses),
net - - (3) - -
Finance
charges - 6 12 (7) 92
Income tax
expense
(recovery) 1 3 (1) - 14
----------------------------------------------------------------------------
Net earnings
(loss) 6 8 (10) - 77
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 12 - 12
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 6 8 (22) - 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,570
Identifiable
assets 653 620 607 (412) 12,901
----------------------------------------------------------------------------
Total assets 653 620 607 (412) 14,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 57 10 - - 282
----------------------------------------------------------------------------
----------------------------------------------------------------------------
REGULATED UTILITIES
--------------------------------------------------------------
Gas &
GasElectric Electric
--------------------------------------------------------------
Fortis-
BC Fortis- New- Total
Year-to-Date Energy Central BC found- Other Electric Electric
June 30, 2013 Cana- Hudson Fortis Elec- land Cana- Cana- Carib-
($ millions) dian US Alberta tric Power dian dian bean
----------------------------------------------------------------------------
Revenue 738 - 235 156 329 183 903 136
Energy supply
costs 322 - - 39 225 118 382 84
Operating
expenses 137 - 78 42 39 25 184 16
Depreciation
and
amortization 92 - 72 25 25 14 136 17
----------------------------------------------------------------------------
Operating
income 187 - 85 50 40 26 201 19
Other income
(expenses),
net 1 - 2 1 1 - 4 1
Finance
charges 71 - 35 19 18 10 82 7
Income tax
expense
(recovery) 26 - 1 6 (8) 1 - -
----------------------------------------------------------------------------
Net earnings
(loss) before
extraordinary
item 91 - 51 26 31 15 123 13
Extraordinary
gain, net of
tax - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss) 91 - 51 26 31 15 123 13
Non-
controlling
interests - - - - - - - 4
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 91 - 51 26 31 15 123 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 486 227 235 - 67 529 149
Identifiable
assets 4,528 1,763 2,927 1,748 1,394 691 6,760 680
----------------------------------------------------------------------------
Total assets 5,441 2,249 3,154 1,983 1,394 758 7,289 829
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 92 - 230 33 38 28 329 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2012
($ millions)
----------------------------------------------------------------------------
Revenue 812 - 218 154 322 173 867 130
Energy supply
costs 411 - - 38 221 109 368 79
Operating
expenses 133 - 76 42 37 24 179 17
Depreciation
and
amortization 80 - 65 24 22 13 124 16
----------------------------------------------------------------------------
Operating
income 188 - 77 50 42 27 196 18
Other income
(expenses),
net 1 - 2 - 1 - 3 1
Finance
charges 71 - 32 20 18 11 81 7
Income tax
expense
(recovery) 22 - - 5 7 4 16 -
----------------------------------------------------------------------------
Net earnings
(loss) 96 - 47 25 18 12 102 12
Non-
controlling
interests 1 - - - - - - 3
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 95 - 47 25 18 12 102 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 - 227 221 - 67 515 142
Identifiable
assets 4,566 - 2,575 1,671 1,298 692 6,236 631
----------------------------------------------------------------------------
Total assets 5,479 - 2,802 1,892 1,298 759 6,751 773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 78 - 200 33 36 22 291 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------------
Year-to-Date Inter-
June 30, 2013 Fortis Non- Corporate segment
($ millions) Generation Utility and Other eliminations Total
----------------------------------------------------------------------------
Revenue 12 118 13 (17) 1,903
Energy supply
costs - - - (1) 787
Operating
expenses 5 83 6 (4) 427
Depreciation
and
amortization 2 11 1 - 259
----------------------------------------------------------------------------
Operating
income 5 24 6 (12) 430
Other income
(expenses),
net - - (44) - (38)
Finance
charges - 12 21 (12) 181
Income tax
expense
(recovery) - 3 (33) - (4)
----------------------------------------------------------------------------
Net earnings
(loss) before
extraordinary
item 5 9 (26) - 215
Extraordinary
gain, net of
tax 22 - - - 22
----------------------------------------------------------------------------
Net earnings
(loss) 27 9 (26) - 237
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 28 - 28
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 27 9 (54) - 205
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 2,077
Identifiable
assets 832 808 643 (458) 15,556
----------------------------------------------------------------------------
Total assets 832 808 643 (458) 17,633
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 79 24 - - 548
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2012
($ millions)
----------------------------------------------------------------------------
Revenue 18 116 13 (15) 1,941
Energy supply
costs - - - (1) 857
Operating
expenses 4 82 6 (3) 418
Depreciation
and
amortization 2 10 1 - 233
----------------------------------------------------------------------------
Operating
income 12 24 6 (11) 433
Other income
(expenses),
net 1 - (8) (1) (3)
Finance
charges 1 12 23 (12) 183
Income tax
expense
(recovery) 1 3 (5) - 37
----------------------------------------------------------------------------
Net earnings
(loss) 11 9 (20) - 210
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 23 - 23
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 11 9 (43) - 183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,570
Identifiable
assets 653 620 607 (412) 12,901
----------------------------------------------------------------------------
Total assets 653 620 607 (412) 14,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures 105 15 - - 511
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 six months ended June 30, 2013 and 2012 were as follows:
Significant Inter-Segment
Transactions Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Sales from Fortis Generation to
Other Canadian Electric
Utilities 1 - 1 -
Sales from Newfoundland Power to
Non-Utility 1 1 3 3
Inter-segment finance charges on
lending from:
Fortis Generation to Other
Canadian Electric Utilities - 1 - 1
Corporate to Regulated
Electric Utilities -
Caribbean 1 1 2 2
Corporate to Fortis Generation - 1 - 1
Corporate to Non-Utility 4 4 9 8
----------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at June 30
($ millions) 2013 2012
----------------------------------------------------------------------------
Inter-segment lending from:
Fortis Generation to Other Canadian
Electric Utilities 20 20
Corporate to Regulated Electric
Utilities - Caribbean 85 77
Corporate to Fortis Generation 6 14
Corporate to Non-Utility 325 281
Other inter-segment assets 22 20
----------------------------------------------------------------------------
Total inter-segment eliminations 458 412
----------------------------------------------------------------------------
----------------------------------------------------------------------------
16. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2013 2012 2013 2012
----------------------------------------------------------------------------
Change in non-cash operating working
capital:
Accounts receivable 205 187 126 128
Prepaid expenses (1) (8) 2 (6)
Inventories (37) (31) 18 27
Regulatory assets - current portion 6 5 40 48
Accounts payable and other current
liabilities (43) (76) (73) (67)
Regulatory liabilities - current
portion (10) 6 25 32
----------------------------------------------------------------------------
120 83 138 162
----------------------------------------
----------------------------------------
Non-cash investing and financing
activities:
Common share dividends reinvested 15 15 34 28
Additions to utility and non-utility
capital assets, and intangible
assets included in current
liabilities 73 72 73 72
Contributions in aid of construction
included in current assets 14 11 14 11
Exercise of stock options into
common shares 1 1 1 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
17. 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 June 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 June 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) 4 - - - -
Electricity swap contracts
(gigawatt hours) 653 876 657 220 219
Gas swaps and options
(petajoules) 7 8 - - -
Gas purchase contract premiums
(petajoules) 46 26 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 were as follows:
As at
June 30, December 31,
($ millions) 2013 2012
----------------------------------------------------------------------------
Gross derivatives balance (1) 34 60
Netting (2) - -
Cash collateral - -
----------------------------------------------------------------------------
Total derivative balances (3) 34 60
------------------------------
------------------------------
(1) Refer to Note 18 for a discussion of the valuation techniques used to
calculate the fair value of the derivative instruments.
(2) Positions, by counterparty, are netted where the intent and legal right
to offset exists.
(3) Unrealized losses of $34 million on commodity risk-related derivative
instruments as at June 30, 2013 were recognized in current regulatory
assets (December 31, 2012 - $60 million), which 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.
18. 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.
As at
Asset (Liability) June 30, 2013 December 31, 2012
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
Long-term other asset -
Belize Electricity (1) 109 n/a(2) 104 n/a (2)
Other investments (1) (3) 9 9 - -
Long-term debt, including
current portion (4) (7,186) (8,220) (5,900) (7,338)
Waneta Partnership
promissory note (5) (48) (50) (47) (51)
Fuel option contracts (6) - - (1) (1)
Electricity swap contracts
(6) (1) (1) - -
Natural gas commodity
derivatives: (6)
Swaps and options (31) (31) (51) (51)
Gas purchase contract
premiums (2) (2) (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 19 and 21).
(3) Other investments represent a portion of the trust assets for the
funding of CH Energy Group's Directors and Executives Deferred
Compensation Plan. These 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 $829 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 June 30, 2013 and December 31,
2012. The fair value of the fuel option contracts as at June 30, 2013
was less than $1 million. The fair value of electricity swap contracts
were 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 mature 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 June 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.
19. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit Risk Risk that a 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 June 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 $1 million by obtaining from the
retailers either a cash deposit, bond, letter of credit or an investment-grade
credit rating from a major rating agency, or by having the retailer obtain a
financial guarantee from an entity with an investment-grade credit rating.
The FortisBC Energy companies may be exposed to credit risk in the event of
non-performance by counterparties to derivative instruments. The Company uses
netting arrangements to reduce credit risk and net settles payments with
counterparties where net settlement provisions exist. The following table
summarizes the FortisBC Energy companies' net credit risk exposure to its
counterparties, as well as credit risk exposure to counterparties accounting for
greater than 10% net credit exposure, as it relates to its natural gas swaps and
options.
As at
June 30, December 31,
($ millions, except as noted) 2013 2012
----------------------------------------------------------------------------
Gross credit exposure before credit collateral
(1) 31 51
Credit collateral - -
----------------------------------------------------------------------------
Net credit exposure (2) 31 51
----------------------------------------------------------------------------
Number of counterparties greater than 10% (#) 4 4
Net exposure to counterparties greater than 10% 29 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 June 30, 2013, the Corporation had a long-term other asset of $109 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 18 and 21).
Additionally, as at June 30, 2013, Belize Electricity owed Belize Electric
Company Limited ("BECOL") approximately US$7 million for energy purchases of
which US$3 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 June 30,
2013, average annual consolidated long-term debt maturities and repayments over
the next five years are expected to be approximately $310 million, excluding
borrowings under the Corporation's committed credit facility which are expected
to be replaced with long-term financing. 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 June 30, 2013, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.7 billion, of which $1.7 billion was
unused, including $395 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 $2.6 billion of the
total credit facilities are committed facilities with maturities ranging from
2013 to 2018.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
December
Regulated Non- Corporate June 30, 31,
($ millions) Utilities Regulated and Other 2013 2012
----------------------------------------------------------------------------
Total credit facilities 1,560 112 1,030 2,702 2,460
Credit facilities
utilized:
Short-term borrowings
(1) (72) (27) - (99) (136)
Long-term debt (2) (226) - (603) (829) (150)
Letters of credit
outstanding (66) - (2) (68) (67)
----------------------------------------------------------------------------
Credit facilities unused 1,196 85 425 1,706 2,107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The weighted average interest rate on short-term borrowings was
approximately 1.7% as at June 30, 2013 (December 31, 2012 - 1.9%).
(2) As at June 30, 2013, credit facility borrowings classified as long term
included $65 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 1.7% as at June 30, 2013 (December
31, 2012 - 2.1%).
As at June 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$31 million ($33 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 ($13 million), a capital
expenditure line of credit of US$10 million ($11 million) and a US$9 million ($9
million) emergency standby loan. The capital expenditure line of credit matures
in December 2013. The remaining facilities mature in June 2014. The new credit
facilities reflect a decrease in pricing but otherwise contain terms and
conditions substantially similar to the previous facilities.
As at June 30, 2013, CH Energy Group had a US$100 million ($105 million)
unsecured revolving credit facility maturing in October 2015, and Central Hudson
had a US$150 million ($158 million) unsecured committed revolving credit
facility maturing in October 2016.
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.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
June 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
plans for 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 investment in, foreign subsidiaries are
exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The
Corporation has effectively decreased the above-noted exposure through the use
of US dollar-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 June 30, 2013, the Corporation's corporately issued US$1,052 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 June 30,
2013, the Corporation had approximately US$534 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 June 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 21). 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 gain of
approximately $3 million and $5 million for the three and six months ended June
30 2013, respectively ($2 million and $0.5 million for the three and six months
ended June 30 2012, respectively) (Note 9).
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 17 and 18). 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.
20. 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 $46
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 megawatts of capacity and 1,752
gigawatt hours 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 expires on September 30, 2013. An executed version of the new
PPA was submitted by BC Hydro to the BCUC in May 2013 and is pending regulatory
approval. 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 $85 million as at June 30, 2013. These obligations are
predominately for long-term storage and interstate gas transportation contracts
and are based on tariff rates as at June 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. In the event the
counterparty is unable to fulfill the commitment to deliver under the terms of
the agreement, Central Hudson would obtain required supply from the New York
Independent System Operator ("NYISO") market, with cost recovery from customers.
Central Hudson must also acquire sufficient peak load capacity to meet the peak
load requirements of its full-service customers. This capacity is made up of
contracts with capacity providers, purchases from the NYISO capacity market and
its own generating capacity. Obligations in respect of electricity purchase
agreements totalled $50 million as at June 30, 2013.
Central Hudson has various purchase commitments and contracts related to ongoing
projects and operating activities with an obligation totalling approximately
$145 million as at June 30, 2013. Certain of these commitments are related to
capital projects and are also included in Central Hudson's capital expenditure
forecast.
21. 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 $109 million, including foreign exchange impacts, as at June
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 $109 million long-term
other asset is not deemed impaired as at June 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.
22. 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 11).
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 1800s with all sites ceasing operations by
the 1950s. 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
June 30, 2013, an obligation of US$9 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 3,340 asbestos cases have been
raised, 1,168 remained pending as at June 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.
23. SUBSEQUENT EVENTS
On July 10, 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.
On July 18, 2013, the Corporation issued 10 million Cumulative Redeemable Fixed
Rate Reset First Preference Shares, Series K at $25.00 per share for gross
proceeds of $250 million. The net proceeds of the offering were used to repay a
portion of borrowings under the Corporation's $1 billion committed corporate
credit facility, including amounts borrowed in connection with the above-noted
redemption of the Corporation's First Preference Shares, Series C, the
construction of the Waneta Expansion and equity injections into certain of the
Corporation's subsidiaries, and for general corporate purposes.
On July 19, 2013, the Corporation priced 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 offering is scheduled to close on October 1, 2013. Proceeds from the
offering will be used to repay a portion of the Corporation's US
dollar-denominated committed credit facility borrowings incurred to initially
finance a portion of the CH Energy Group acquisition.
On July 26, 2013, applications for rehearing of the approval of the CH Energy
Group acquisition were filed with the PSC. In addition, the parties petitioned
the PSC to designate Central Hudson's rates as temporary pending further review
of certain matters, including the Company's allowed ROE. The Corporation is
preparing a response to the applications, which it expects to file shortly.
24. 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
approximately 2.4 million gas and electricity 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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