Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved first quarter net
earnings attributable to common equity shareholders of $121 million, or $0.64
per common share, compared to $116 million, or $0.66 per common share, for the
first quarter of 2011. Performance was driven by the FortisBC Energy companies.
The decrease in earnings per common share quarter over quarter mainly related to
an 8% increase in the weighted average number of common shares outstanding,
largely associated with the public common equity offering in mid-2011, and the
$4 million, or $0.02 per common share, one-time acquisition-related expenses
associated with the CH Energy Group, Inc. ("CH Energy Group") transaction
discussed below.
Common shareholders of Fortis received a dividend of 30 cents per common share
on March 1, 2012, up from 29 cents in the fourth quarter of 2011. The 3.4%
increase in the quarterly common share dividend translates into an annualized
dividend of $1.20 and extends the Corporation's record of annual common share
dividend increases to 39 consecutive years, the longest record of any public
corporation in Canada.
Canadian Regulated Gas Utilities delivered earnings of $82 million, up $7
million from the first quarter of 2011. The increase in earnings was mainly due
to: (i) seasonality of gas consumption and the timing of certain expenses in
2012; (ii) growth in energy infrastructure investment; and (iii) increased gas
transportation volumes to the forestry and mining sectors. The increase was
partially offset by lower-than-expected customer additions and lower capitalized
allowance for funds used during construction. Due to the seasonality of the
business, most of the earnings of the regulated gas utilities are realized in
the first and fourth quarters.
Canadian Regulated Electric Utilities contributed earnings of $51 million,
compared to $52 million for the first quarter of 2011. The slight decrease in
earnings was largely the result of the discontinuance of the performance-based
rate-setting ("PBR") mechanism and the timing of certain operating expenses in
2012 at FortisBC Electric, partially offset by higher electricity sales and
lower effective corporate income taxes at Newfoundland Power and Maritime
Electric. Excluding the approximate $1 million gain on sale of property in the
first quarter of 2011, earnings at FortisAlberta improved quarter over quarter
as a result of growth in energy infrastructure investment, partially offset by
the impact of a lower allowed rate of return on common shareholders' equity.
"Recent regulatory decisions at FortisAlberta and the FortisBC Energy companies
provide a measure of regulatory stability for our western Canadian utilities,"
says Stan Marshall, President and Chief Executive Officer, Fortis Inc. In April
2012 regulatory decisions were received for 2012/2013 customer gas delivery
rates at the FortisBC Energy companies and 2012 customer electricity
distribution rates at FortisAlberta. A decision on 2012/2013 customer
electricity rates at FortisBC Electric is expected mid-2012. "It remains a very
busy period on the regulatory front as a number of regulatory processes are
underway at FortisBC, FortisAlberta and Newfoundland Power," he explains. A
Generic Cost of Capital Proceeding in British Columbia to determine cost of
capital, effective January 1, 2013, and a PBR rate-regulation initiative in
Alberta are in progress. A Cost of Capital Application was filed by Newfoundland
Power in March 2012.
Caribbean Regulated Electric Utilities contributed $3 million to earnings
compared to $4 million for the first quarter of 2011. The decrease in earnings
was due to higher finance charges and operating and depreciation expenses.
Non-Regulated Fortis Generation contributed $5 million to earnings, up $2
million from the first quarter of 2011. Improved performance was the result of
higher production in Belize due to higher rainfall.
Fortis Properties delivered earnings of $1 million, comparable to the first
quarter of 2011.
Corporate and other expenses were $21 million, $2 million higher quarter over
quarter, largely the result of CH Energy Group acquisition-related expenses
incurred in the first quarter of 2012, partially offset by lower finance
charges.
Cash flow from operating activities was $328 million for the quarter, up $26
million from the first quarter of 2011, driven by favourable changes in working
capital, largely associated with current regulatory deferral accounts, and
higher earnings.
Fortis retroactively adopted accounting principles generally accepted in the
United States ("US GAAP"), effective January 1, 2012, with the restatement of
prior periods. The adoption of US GAAP did not have a material impact on the
Corporation's earnings per common share for the first quarter of 2012 or 2011.
In February 2012 Fortis entered into an agreement to acquire CH Energy Group for
approximately US$1.5 billion, including the assumption of approximately $500
million of debt on closing. Central Hudson Gas & Electric Corporation ("Central
Hudson"), the main business of CH Energy Group, is a regulated transmission and
distribution utility serving approximately 300,000 electric and 75,000 natural
gas customers in eight counties of New York State's Mid-Hudson River Valley.
The closing of the acquisition is subject to the receipt of CH Energy Group's
common shareholders' approval, regulatory and other approvals, and satisfaction
of customary closing conditions. The acquisition is expected to be immediately
accretive to earnings per common share of Fortis, excluding one-time
acquisition-related expenses. In April 2012 applications were filed with the New
York State Public Service Commission and Federal Energy Regulatory Commission
seeking approval of the transaction. The CH Energy Group shareholder vote on the
transaction is expected to occur mid-2012.
Consolidated capital expenditures, before customer contributions, were
approximately $229 million in the first quarter of 2012. The Customer Care
Enhancement Project at FortisBC's gas business came into service in January
2012. Construction continues on the $900 million Waneta Expansion hydroelectric
generating facility ("Waneta Expansion") with excavation of the intake,
powerhouse and power tunnels completed. Approximately $290 million has been
spent on the Waneta Expansion since construction began in late 2010.
"Fortis utilities are well underway towards completing their 2012 capital
projects to meet the energy needs of our customers," says Marshall. "Our 2012
consolidated capital expenditure program is expected to be $1.3 billion. Over
the next five years through 2016, our capital program is expected to total $5.5
billion. This investment should support continuing growth in earnings and
dividends," says Marshall.
"Fortis is working to close the acquisition of CH Energy Group, which is
expected to occur by the end of the first quarter of 2013," says Marshall. "We
remain disciplined and patient in our pursuit of additional electric and gas
utility acquisitions in the United States and Canada that will add value for
Fortis shareholders," concludes Marshall.
Interim Management Discussion and Analysis
For the three months ended March 31, 2012
Dated May 2, 2012
FORWARD-LOOKING STATEMENT
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion
and Analysis ("MD&A") has been prepared in accordance with National Instrument
51-102 - Continuous Disclosure Obligations. Financial information for 2012 and
comparative periods contained in the MD&A has been prepared in accordance with
accounting principles generally accepted in the United States ("US GAAP") and is
presented in Canadian dollars unless otherwise specified. The MD&A should be
read in conjunction with the following: (i) the interim unaudited consolidated
financial statements and notes thereto for the three months ended March 31,
2012, prepared in accordance with US GAAP; (ii) the audited consolidated
financial statements and notes thereto for the year ended December 31, 2011,
prepared in accordance with US GAAP and voluntarily filed on the System for
Electronic Document Analysis and Retrieval ("SEDAR") by Fortis on March 16,
2012; (iii) the audited consolidated financial statements and notes thereto for
the year ended December 31, 2011, prepared in accordance with Canadian generally
accepted accounting principles ("Canadian GAAP"); (iv) the "Supplemental Interim
Consolidated Financial Statements for the Year Ended December 31, 2011
(Unaudited)" contained in the above-noted voluntary filing which provides a
detailed reconciliation between the Corporation's interim unaudited consolidated
2011 Canadian GAAP financial statements and interim unaudited consolidated 2011
US GAAP financial statements; and (v) the MD&A for the year ended December 31,
2011 included in the Corporation's 2011 Annual Report.
Fortis includes forward-looking information in the MD&A within the meaning of
applicable securities laws in Canada ("forward-looking information"). The
purpose of the forward-looking information is to provide management's
expectations regarding the Corporation's future growth, results of operations,
performance, business prospects and opportunities, and it may not be appropriate
for other purposes. All forward-looking information is given pursuant to the
safe harbour provisions of applicable Canadian securities legislation. The words
"anticipates", "believes", "budgets", "could", "estimates", "expects",
"forecasts", "intends", "may", "might", "plans", "projects", "schedule",
"should", "will", "would" and similar expressions are often intended to identify
forward-looking information, although not all forward-looking information
contains these identifying words. The forward-looking information reflects
management's current beliefs and is based on information currently available to
the Corporation's management. The forward-looking information in the MD&A
includes, but is not limited to, statements regarding: the Corporation's
consolidated forecast gross capital expenditures for 2012 and in total over the
five-year period 2012 through 2016; the nature, timing and amount of certain
capital projects and their expected costs and time to complete; the expectation
that the Corporation's significant capital expenditure program should support
continuing growth in earnings and dividends; forecast midyear rate base; the
expectation that cash required to complete subsidiary capital expenditure
programs will be sourced from a combination of cash from operations, borrowings
under credit facilities, equity injections from Fortis and long-term debt
offerings; the expected consolidated long-term debt maturities and repayments on
average annually over the next five years; except for debt at the Exploits River
Hydro Partnership ("Exploits Partnership"), the expectation that the Corporation
and its subsidiaries will remain compliant with debt covenants during 2012; the
expected timing of filing of regulatory applications and of receipt of
regulatory decisions; the expected timing of the closing of the acquisition of
CH Energy Group, Inc. ("CH Energy Group") by Fortis and the expectation that the
acquisition will be immediately accretive to earnings per common share,
excluding one-time acquisition-related expenses; and the expectation of an
increase in the Corporation's committed corporate credit facility from $800
million to $1 billion.
The forecasts and projections that make up the forward-looking information are
based on assumptions which include, but are not limited to: the receipt of
applicable regulatory approvals and requested rate orders; no significant
variability in interest rates; no significant operational disruptions or
environmental liability due to a catastrophic event or environmental upset
caused by severe weather, other acts of nature or other major events; the
continued ability to maintain the gas and electricity systems to ensure their
continued performance; no severe and prolonged downturn in economic conditions;
no significant decline in capital spending; no material capital project and
financing cost overrun related to the construction of the Waneta Expansion
hydroelectric generating facility; sufficient liquidity and capital resources;
the expectation that the Corporation will receive appropriate compensation from
the Government of Belize ("GOB") for fair value of the Corporation's investment
in Belize Electricity that was expropriated by the GOB; the expectation that
Belize Electric Company Limited ("BECOL") will not be expropriated by the GOB;
the expectation that the Corporation will receive fair compensation from the
Government of Newfoundland and Labrador related to the expropriation of the
Exploits Partnership's hydroelectric assets and water rights; the continuation
of regulator-approved mechanisms to flow through the commodity cost of natural
gas and energy supply costs in customer rates; the ability to hedge exposures to
fluctuations in interest rates, foreign exchange rates, natural gas commodity
prices and fuel prices; no significant counterparty defaults; the continued
competitiveness of natural gas pricing when compared with electricity and other
alternative sources of energy; the continued availability of natural gas, fuel
and electricity supply; continuation and regulatory approval of power supply and
capacity purchase contracts; the 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 affect the operations and cash
flows of the Corporation and its subsidiaries; maintenance of adequate insurance
coverage; the ability to obtain and maintain licences and permits; retention of
existing service areas; the ability to report under US GAAP beyond 2014 or the
adoption of International Financial Reporting Standards ("IFRS") after 2014 that
allows for the recognition of regulatory assets and liabilities; the continued
tax-deferred treatment of earnings from the Corporation's Caribbean operations;
continued maintenance of information technology ("IT") infrastructure; continued
favourable relations with First Nations; favourable labour relations; and
sufficient human resources to deliver service and execute the capital program.
The forward-looking information is subject to risks, uncertainties and other
factors that could cause actual results to differ materially from historical
results or results anticipated by the forward-looking information. Factors which
could cause results or events to differ from current expectations include, but
are not limited to: regulatory risk; interest rate risk, including the
uncertainty of the impact a continuation of a low interest rate environment may
have on allowed rates of return on common shareholders' equity of the
Corporation's regulated utilities; operating and maintenance risks; risk
associated with changes in economic conditions; capital project budget overrun,
completion and financing risk in the Corporation's non-regulated business;
capital resources and liquidity risk; risk associated with the amount of
compensation to be paid to Fortis for its investment in Belize Electricity that
was expropriated by the GOB; the timeliness of the receipt of the compensation
and the ability of the GOB to pay the compensation owing to Fortis; risk that
the GOB may expropriate BECOL; an ultimate resolution of the expropriation of
the hydroelectric assets and water rights of the Exploits Partnership that
differs from that which is currently expected by management; weather and
seasonality risk; commodity price risk; the continued ability to hedge foreign
exchange risk; counterparty risk; competitiveness of natural gas; natural gas,
fuel and electricity supply risk; risk associated with the continuation,
renewal, replacement and/or regulatory approval of power supply and capacity
purchase contracts; risks relating to the ability to, and timing of, close of
the acquisition of CH Energy Group and the realization of the benefits of the
acquisition; the risk associated with defined benefit pension plan performance
and funding requirements; risks related to FortisBC Energy (Vancouver Island)
Inc.; environmental risks; insurance coverage risk; risk of loss of licences and
permits; risk of loss of service area; risk of not being able to report under US
GAAP beyond 2014 or risk that IFRS does not have an accounting standard for
rate-regulated entities by the end of 2014 allowing for the recognition of
regulatory assets and liabilities; risks related to changes in tax legislation;
risk of failure of IT infrastructure; risk of not being able to access First
Nations lands; labour relations risk; human resources risk; and risk of
unexpected outcomes of legal proceedings currently against the Corporation. For
additional information with respect to the Corporation's risk factors, reference
should be made to the Corporation's continuous disclosure materials filed from
time to time with Canadian securities regulatory authorities and to the heading
"Business Risk Management" in the MD&A for the three months ended March 31, 2012
and for the year ended December 31, 2011.
All forward-looking information in the MD&A is qualified in its entirety by the
above cautionary statements and, except as required by law, the Corporation
undertakes no obligation to revise or update any forward-looking information as
a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is the largest investor-owned distribution utility in Canada, serving
more than 2,000,000 gas and electricity customers. Its regulated holdings
include electric utilities in five Canadian provinces and two Caribbean
countries and a natural gas utility in British Columbia, Canada. Fortis owns
non-regulated generation assets, primarily hydroelectric, across Canada and in
Belize and Upper New York State, and hotels and commercial office and retail
space in Canada. Year-to-date March 31, 2012, the Corporation's electricity
distribution systems met a combined peak demand of approximately 5,183 megawatts
("MW") and its gas distribution system met a peak day demand of 1,335 terajoules
("TJ"). For additional information on the Corporation's business segments, refer
to Note 1 to the Corporation's interim unaudited consolidated financial
statements for the three months ended March 31, 2012 and to the "Corporate
Overview" section of the 2011 Annual MD&A.
The key goals of the Corporation's regulated utilities are to operate sound gas
and electricity distribution systems, deliver gas and electricity safely and
reliably at the lowest reasonable cost and conduct business in an
environmentally responsible manner. The Corporation's main business, utility
operations, is highly regulated and the earnings of the Corporation's regulated
utilities are primarily determined under cost of service ("COS") regulation.
Generally under COS regulation, the respective regulatory authority sets
customer gas and/or electricity rates to permit a reasonable opportunity for the
utility to recover, on a timely basis, estimated costs of providing service to
customers, including a fair rate of return on a regulatory deemed or targeted
capital structure applied to an approved regulatory asset value ("rate base").
Generally, the ability of a regulated utility to recover prudently incurred
costs of providing service and earn the regulator-approved rate of return on
common shareholders' equity ("ROE") and/or rate of return on rate base assets
("ROA") depends on the utility achieving the forecasts established in the
rate-setting processes. As such, earnings of regulated utilities are generally
impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA; (ii)
changes in rate base; (iii) changes in energy sales or gas delivery volumes;
(iv) changes in the number and composition of customers; (v) variances between
actual expenses incurred and forecast expenses used to determine revenue
requirements and set customer rates; and (vi) timing differences within an
annual financial reporting period, between when actual expenses are incurred and
when they are recovered from customers in rates. When forward test years are
used to establish revenue requirements and set base customer rates, these rates
are not adjusted as a result of actual COS being different from that which 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.
Pending Acquisition of CH Energy Group, Inc.: On February 21, 2012, Fortis
announced that it had entered into an agreement to acquire CH Energy Group, Inc.
("CH Energy Group") for US$65.00 per common share in cash, for an aggregate
purchase price of approximately US$1.5 billion, including the assumption of
approximately US$500 million of debt on closing (the "Acquisition"). CH Energy
Group is an energy delivery company headquartered in Poughkeepsie, New York. Its
main business, Central Hudson Gas & Electric Corporation, is a regulated
transmission and distribution ("T&D") utility serving approximately 300,000
electric and 75,000 natural gas customers in eight counties of New York State's
Mid-Hudson River Valley. The closing of the Acquisition, which is expected by
the end of the first quarter of 2013, is subject to receipt of CH Energy Group's
common shareholders' approval, regulatory and other approvals, and the
satisfaction of customary closing conditions. The acquisition is expected to be
immediately accretive to earnings per common share of Fortis, excluding one-time
acquisition-related expenses. Fortis and CH Energy Group filed a joint petition
with the New York State Public Service Commission in April 2012 for approval of
the acquisition of all of the outstanding stock of CH Energy Group by Fortis
and, indirectly, ownership of Central Hudson, and related transactions. The vote
on the acquisition by CH Energy Group's shareholders is expected to occur
mid-2012. Also, an application was filed in April 2012 with the Federal Energy
Regulatory Commission seeking similar approvals.
Transition to US GAAP: In June 2011 the Ontario Securities Commission issued a
decision allowing Fortis and its reporting issuer subsidiaries to prepare their
financial statements, effective January 1, 2012 through to December 31, 2014, in
accordance with US GAAP without qualifying as U.S. Securities and Exchange
Commission ("SEC") Issuers pursuant to Canadian securities laws. The Corporation
and its reporting issuer subsidiaries, therefore, adopted US GAAP as opposed to
International Financial Reporting Standards ("IFRS") on January 1, 2012.
Earnings recognized under US GAAP are more closely aligned with earnings
recognized under Canadian GAAP, mainly due to the continued recognition of
regulatory assets and liabilities under US GAAP. A transition to IFRS would
likely have resulted in the derecognition of some, or perhaps all, of the
Corporation's regulatory assets and liabilities and significant volatility in
the Corporation's consolidated earnings. On March 16, 2012, Fortis voluntarily
prepared and filed audited consolidated US GAAP financial statements for the
year ended December 31, 2011, with 2010 comparatives. Also included in the
voluntary filing were: (i) a detailed reconciliation between the Corporation's
audited consolidated Canadian GAAP and audited consolidated US GAAP financial
statements for fiscal 2011, including 2010 comparatives; and (ii) a detailed
reconciliation between the Corporation's 2011 interim unaudited consolidated
Canadian GAAP and 2011 interim unaudited consolidated US GAAP financial
statements. For further information, refer to the "Changes in Accounting
Policies" section of this MD&A.
Expropriated Assets - Belize Electricity: There were no material changes during
the first quarter of 2012 with respect to matters pertaining to the
expropriation of Belize Electricity from those disclosed in the Corporation's
2011 Annual MD&A. Court proceedings continue in the Belize Supreme Court in
respect of the Corporation's challenge to the expropriation.
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 first quarters ended
March 31, 2012 and March 31, 2011 are provided in the following table.
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Consolidated Financial Highlights
(Unaudited) Quarter Ended March 31
($ millions, except for common share
data) 2012 2011 Variance
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Revenue 1,149 1,159 (10)
Energy Supply Costs 566 603 (37)
Operating Expenses 214 210 4
Depreciation and Amortization 119 103 16
Other Income (Expenses), Net (3) 8 (11)
Finance Charges 91 92 (1)
Income Taxes 23 31 (8)
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Net Earnings 133 128 5
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Net Earnings Attributable to:
Non-Controlling Interests 1 1 -
Preference Equity Shareholders 11 11 -
Common Equity Shareholders 121 116 5
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Net Earnings 133 128 5
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Basic Earnings per Common Share ($) 0.64 0.66 (0.02)
Diluted Earnings per Common Share ($) 0.62 0.64 (0.02)
Weighted Average Number of Common Shares
Outstanding (# millions) 189.0 175.0 14.0
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Cash Flow from Operating Activities 328 302 26
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Factors Contributing to Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Lower average gas consumption by residential and commercial customers,
partially offset by higher gas transportation volumes to the forestry
and mining sectors
Favourable
-- An increase in gas delivery rates and the base component of electricity
rates at the regulated utilities in western Canada, consistent with
interim rate decisions, reflecting ongoing investment in energy
infrastructure and forecasted higher expenses recoverable from customers
-- Growth in the number of customers, driven by FortisAlberta, and higher
average electricity consumption at most of the regulated electric
utilities
-- The flow through in customer electricity rates of overall higher energy
supply costs, driven by Caribbean Utilities
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
-- Higher Hospitality revenue at Fortis Properties, driven by contribution
from the Hilton Suites Winnipeg Airport hotel, which was acquired in
October 2011
Factors Contributing to Energy Supply Costs Variance
Favourable
-- Lower commodity cost of natural gas
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Lower average gas consumption
-- Lower purchased power costs at Maritime Electric
Unfavourable
-- Increased fuel prices at Caribbean Utilities and purchased power costs
at FortisBC Electric
-- Higher electricity sales
Factors Contributing to Operating Expenses Variance
Unfavourable
-- General inflationary and employee-related cost increases at the
Corporation's regulated utilities and timing of expenditures at FortisBC
Electric
-- Operating expenses associated with the Hilton Suites Winnipeg Airport
hotel, which was acquired in October 2011
Favourable
-- Lower operating expenses at the FortisBC Energy companies, mainly due to
the accrual of non-asset retirement obligation ("non-ARO") removal costs
in depreciation, effective January 1, 2012, and lower customer care-
related costs as a result of insourcing the customer care function,
effective January 1, 2012
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
Factors Contributing to Depreciation and Amortization Costs Variance
Unfavourable
-- Continued investment in energy infrastructure
-- Increased depreciation at the FortisBC Energy companies, mainly due to
the accrual of non-ARO removal costs in depreciation, effective January
1, 2012, as discussed above
Favourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
Factors Contributing to Other Income (Expenses), Net Variance
Unfavourable
-- Approximately $4 million of costs incurred in the first quarter of 2012
related to the pending acquisition of CH Energy Group
-- Lower capitalized equity component of allowance for funds used during
construction ("AFUDC"), mainly at the FortisBC Energy companies and
FortisBC Electric
-- An approximate $1.5 million foreign exchange loss associated with the
translation of the US dollar-denominated long-term other asset
representing the book value of the Corporation's former investment in
Belize Electricity
-- An approximate $1 million gain on the sale of property at FortisAlberta
during the first quarter of 2011
Factors Contributing to Finance Charges Variance
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")
-- Lower corporate credit facility borrowings, due to the repayment of
borrowings during the third quarter of 2011 with a portion of the
proceeds from the public common equity offering in mid-2011
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- Lower short-term borrowings at the regulated utilities
Unfavourable
-- Higher long-term debt levels in support of the utilities' capital
expenditure programs
-- Lower capitalized debt component of AFUDC mainly at the FortisBC Energy
companies and FortisBC Electric
Factors Contributing to Income Taxes Variance
Favourable
-- Lower statutory income tax rates
-- Lower earnings before income taxes
-- Higher deductions for income tax purposes compared to accounting
purposes
Factors Contributing to Earnings Variance
Favourable
-- Increased earnings at the FortisBC Energy companies, mainly due to
seasonality of gas consumption and the timing of certain expenses in
2012, combined with growth in energy infrastructure investment and
higher gas transportation volumes to the forestry and mining sectors.
The increase was partially offset by lower-than-expected customer
additions and lower capitalized AFUDC.
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
-- Higher earnings at Newfoundland Power and Maritime Electric, mainly due
to increased electricity sales and lower effective corporate income
taxes
Unfavourable
-- The expiry of the performance-based rate-setting ("PBR") mechanism on
December 31, 2011 at FortisBC Electric and the timing of certain
operating expenses at the utility in 2012
-- Higher corporate expenses due to approximately $4 million of costs
incurred in the first quarter of 2012 related to the pending acquisition
of CH Energy Group and a $1.5 million foreign exchange loss, partially
offset by lower finance charges
-- An approximate $1 million gain on the sale of property at FortisAlberta
during the first quarter of 2011
SEGMENTED RESULTS OF OPERATIONS
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Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited) Quarter Ended March 31
($ millions) 2012 2011 Variance
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Regulated Gas Utilities - Canadian
FortisBC Energy Companies 82 75 7
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Regulated Electric Utilities - Canadian
FortisAlberta 21 21 -
FortisBC Electric 16 19 (3)
Newfoundland Power 7 6 1
Other Canadian Electric Utilities 7 6 1
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51 52 (1)
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Regulated Electric Utilities - Caribbean 3 4 (1)
Non-Regulated - Fortis Generation 5 3 2
Non-Regulated - Fortis Properties 1 1 -
Corporate and Other (21) (19) (2)
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Net Earnings Attributable to Common
Equity Shareholders 121 116 5
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For a discussion of the nature of regulation and material regulatory decisions
and applications pertaining to the Corporation's regulated utilities, refer to
the "Regulatory Highlights" section of this MD&A. A discussion of the financial
results of the Corporation's reporting segments is as follows.
REGULATED GAS UTILITIES - CANADIAN
FORTISBC ENERGY COMPANIES(1)
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Gas Volumes by Major Customer Category
(Unaudited) Quarter Ended March 31
(TJ) 2012 2011 Variance
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Core - Residential and Commercial 48,532 50,448 (1,916)
Industrial 1,771 1,888 (117)
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Total Sales Volumes 50,303 52,336 (2,033)
Transportation Volumes 21,469 20,484 985
Throughput under Fixed Revenue Contracts 607 476 131
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Total Gas Volumes 72,379 73,296 (917)
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(1) Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver
Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI")
Factors Contributing to Gas Volumes Variances
Unfavourable
-- Lower average gas consumption by residential and commercial customers as
a result of overall warmer temperatures
Favourable
-- Higher gas transportation volumes reflecting improved economic
conditions favourably affecting the forestry and mining sectors
Net customer additions were 1,000 during the first quarter of 2012 compared to
1,400 during the same quarter in 2011. Net customer additions decreased due to
lower building activity during 2012. With the implementation of the new Customer
Care Enhancement Project on January 1, 2012, the FortisBC Energy companies
changed their definition of a customer. As a result of this change, FEI adjusted
its customer count downwards by approximately 17,000, effective January 1, 2012.
As at March 31, 2012, the total number of customers served by the FortisBC
Energy companies was approximately 939,000.
The FortisBC Energy companies earn approximately the same margin regardless of
whether a customer contracts for the purchase and delivery of natural gas or
only for the delivery of natural gas. As a result of the operation of
regulator-approved deferral mechanisms, changes in consumption levels and the
commodity cost of natural gas from those forecast to set residential and
commercial customer gas rates do not materially affect earnings.
Seasonality has a material impact on the earnings of the FortisBC Energy
companies as a major portion of the gas distributed is used for space heating.
Most of the annual earnings of the FortisBC Energy companies are realized in the
first and fourth quarters.
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Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2012 2011 Variance
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Revenue 548 574 (26)
Earnings 82 75 7
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Factors Contributing to Revenue Variance
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Lower average gas consumption by residential and commercial customers
Favourable
-- An interim increase in the delivery component of customer rates, mainly
due to ongoing investment in energy infrastructure and forecasted higher
expenses recoverable from customers. A decision on 2012 and 2013
customer delivery rates was received by the FortisBC Energy companies in
April 2012.
-- Higher gas transportation volumes to the forestry and mining sectors
Factors Contributing to Earnings Variance
Favourable
-- The seasonality of gas consumption and the timing of certain expenses in
2012. Revenue is recognized based on seasonal gas consumption while
certain operating expenses, as well as depreciation, are generally
incurred evenly throughout the year.
-- Rate base growth, due to continued investment in energy infrastructure
-- Higher gas transportation volumes to the forestry and mining sectors
Unfavourable
-- Lower-than-expected customer additions in the first quarter of 2012
-- Lower capitalized AFUDC, due to a lower asset base under construction
during the first quarter of 2012
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries (gigawatt hours
("GWh")) 4,482 4,402 80
Revenue ($ millions) 108 100 8
Earnings ($ millions) 21 21 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Energy Deliveries Variance
Favourable
-- Growth in the number of customers, with the total number of customers
increasing by approximately 8,000 quarter over quarter, driven by
favourable economic conditions
-- Higher average consumption by the oilfield sector, due to increased
activity mainly as a result of high market prices for oil
Unfavourable
-- Lower average consumption by residential customers due to warmer-than-
average temperatures during the first quarter of 2012
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 Revenue Variance
Favourable
-- An interim increase in customer electricity distribution rates,
effective January 1, 2012, reflecting the parameters of the Negotiated
Settlement Agreement ("NSA") filed by FortisAlberta in November 2011 for
2012 rates. The interim rate increase was driven primarily by ongoing
investment in energy infrastructure and forecasted higher expenses
recoverable from customers. A decision on the NSA was received in April
2012 approving the interim increase in customer rates as final.
-- Growth in the number of customers
Unfavourable
-- A lower allowed ROE quarter over quarter. The cumulative impact on
revenue, from January 1, 2011, of the decrease in the allowed ROE to
8.75%, effective for both 2011 and 2012, from 9.00% for 2010 was
recognized during the fourth quarter of 2011, when the regulatory
decision was received.
Factors Contributing to Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
Unfavourable
-- An approximate $1 million gain on the sale of property during the first
quarter of 2011
-- Lower-than-expected number of customers and lower-than-expected energy
consumption by residential customers in the first quarter of 2012
-- A lower allowed ROE quarter over quarter
FORTISBC ELECTRIC(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 909 905 4
Revenue ($ millions) 87 83 4
Earnings ($ millions) 16 19 (3)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant
and Arrow Lakes hydroelectric generating plants and the distribution
system owned by the City of Kelowna. Excludes the non-regulated
generation operations of FortisBC Inc.'s wholly owned partnership,
Walden Power Partnership
Factor Contributing to Electricity Sales Variance
Favourable
-- Growth in the number of customers
Factors Contributing to Revenue Variance
Favourable
-- An interim, refundable increase in customer electricity rates, effective
January 1, 2012, mainly reflecting ongoing investment in energy
infrastructure and forecasted higher expenses recoverable from customers
-- A 1.4% increase in customer electricity rates, effective June 1, 2011,
as a result of the flow through to customers of increased purchased
power costs charged to FortisBC Electric by BC Hydro
-- The 0.4% increase in electricity sales
Factors Contributing to Earnings Variance
Unfavourable
-- The expiry of the PBR mechanism on December 31, 2011. During the first
quarter of 2011, lower-than-expected costs, primarily purchased power
costs, were shared equally between customers and FortisBC Electric under
the PBR mechanism. Pursuant to the Company's 2012-2013 Revenue
Requirements Application ("RRA"), which is subject to regulatory
approval, variances between actual purchased power costs and certain
other costs and those used to set customer electricity rates are subject
to full deferral account treatment and, therefore, did not impact
FortisBC Electric's earnings for the first quarter of 2012.
-- Increased operating expenses due to the timing of expenditures in 2012
-- Lower capitalized AFUDC due to a lower asset base under construction
during the first quarter of 2012
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 1,914 1,834 80
Revenue ($ millions) 192 183 9
Earnings ($ millions) 7 6 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Electricity Sales Variance
Favourable
-- Growth in the number of customers
-- Higher average consumption, reflecting the higher concentration of
electric-versus-oil heating in new home construction combined with
economic growth
Factors Contributing to Revenue Variance
Favourable
-- The 4.4% increase in electricity sales
Unfavourable
-- Revenue during the first quarter of 2011 included amounts related to
support structure arrangements, which were in place with Bell Aliant
Inc. ("Bell Aliant") during 2011, associated with the joint-use poles
held for sale to Bell Aliant. The joint-use poles were sold in October
2011.
Factors Contributing to Earnings Variance
Favourable
-- Electricity sales growth
-- Lower effective corporate income taxes, primarily due to a lower
allocation of Part VI.1 tax to Newfoundland Power and a lower statutory
income tax rate
Unfavourable
-- The impact of the support structure arrangements with Bell Aliant during
2011, as discussed above
OTHER CANADIAN ELECTRIC UTILITIES(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales (GWh) 645 654 (9)
Revenue ($ millions) 91 91 -
Earnings ($ millions) 7 6 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Electricity Sales Variance
Unfavourable
-- Lower average consumption by residential and industrial customers in
Ontario, reflecting more moderate temperatures and weakened economic
conditions in the region
Favourable
-- Growth in the number of residential customers and an increase in the
number of residential customers using electricity for home heating on
Prince Edward Island ("PEI")
-- Higher average consumption by commercial customers in the agricultural
processing sector on PEI
Factors Contributing to Revenue Variance
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
-- Increased electricity sales on PEI, for the reason discussed above
Unfavourable
-- Lower basic component of customer rates at Maritime Electric, effective
March 1, 2011, associated with the recovery of energy supply costs
-- Decreased electricity sales in Ontario, for the reason discussed above
Factors Contributing to Earnings Variance
Favourable
-- Lower effective corporate income taxes, primarily due to higher
deductions taken for income tax purposes compared to accounting purposes
and lower statutory income tax rates
-- Increased electricity sales on PEI
REGULATED ELECTRIC UTILITIES - CARIBBEAN(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN Exchange Rate(2) 1.00 0.99 0.01
----------------------------------------------------------------------------
Electricity Sales (GWh) 166 257 (91)
Revenue ($ millions) 63 75 (12)
Earnings ($ millions) 3 4 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which
Fortis holds an approximate 60% controlling interest; wholly owned
Fortis Turks and Caicos; and the financial results of the Corporation's
approximate 70% controlling interest in Belize Electricity up to June
20, 2011. Effective June 20, 2011, the Government of Belize
expropriated the Corporation's investment in Belize Electricity. As a
result of no longer controlling the operations of the utility, Fortis
discontinued the consolidation method of accounting for Belize
Electricity, effective June 20, 2011. For further information, refer to
the "Key Trends and Risks - Expropriated Assets" and "Business Risk
Management - Investment in Belize" sections of the 2011 Annual MD&A.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar. The reporting currency of Belize Electricity
is the Belizean dollar, which is pegged to the US dollar at
BZ$2.00=US$1.00.
Factors Contributing to Electricity Sales Variance
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011. Excluding Belize Electricity, electricity sales increased
approximately 1.7% quarter over quarter.
-- Cooler temperatures and higher rainfall experienced on Grand Cayman,
which decreased air conditioning load
Favourable
-- Growth in the number of customers in Grand Cayman and the Turks and
Caicos Islands
-- Warmer temperatures experienced in the Turks and Caicos Islands, which
increased air conditioning load
Factors Contributing to Revenue Variance
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for Belize Electricity,
effective June 20, 2011
Favourable
-- The flow through in customer electricity rates of higher energy supply
costs at Caribbean Utilities, due to an increase in the cost of fuel
-- Higher electricity sales, excluding Belize Electricity
Factors Contributing to Earnings Variance
Unfavourable
-- Higher depreciation expense and finance charges, excluding Belize
Electricity, largely due to investment in utility capital assets
-- Increased operating expenses, excluding Belize Electricity, mainly
associated with higher insurance expense and employee-related costs at
Caribbean Utilities and the timing of capital projects at Fortis Turks
and Caicos
Favourable
-- Higher electricity sales, excluding Belize Electricity
-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more
fuel-efficient production realized with the commissioning of new
generation units at the utility
NON-REGULATED - FORTIS GENERATION(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 88 76 12
Revenue ($ millions) 9 7 2
Earnings ($ millions) 5 3 2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State, with a combined generating capacity of 139 MW, mainly
hydroelectric
Factors Contributing to Energy Sales Variance
Favourable
-- Increased production in Belize, due to higher rainfall
Unfavourable
-- Decreased production in Upper New York State, due to a generating
facility being out of service
Factor Contributing to Revenue and Earnings Variances
Favourable
-- Increased production in Belize
In May 2011 the generator at Moose River's hydroelectric generating facility in
Upper New York State sustained electrical damage. Equipment and business
interruption insurance claims are ongoing. Revenue for the first quarter of 2012
reflects the accrual of insurance proceeds related to the loss of earnings for
the first quarter of 2012 associated with the shutdown of the facility. The
generator is under repair and the facility is expected to become operational in
May 2012.
NON-REGULATED - FORTIS PROPERTIES(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality - Revenue per Available Room
("RevPAR") ($) 66.54 63.29 3.25
Real Estate - Occupancy Rate (as at, %) 92.2 94.3 (2.1)
----------------------------------------------------------------------------
Hospitality Revenue ($ millions) 35 33 2
Real Estate Revenue ($ millions) 17 17 -
----------------------------------------------------------------------------
Total Revenue ($ millions) 52 50 2
----------------------------------------------------------------------------
Earnings ($ millions) 1 1 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 22 hotels, collectively
representing 4,300 rooms, in eight Canadian provinces and approximately
2.7 million square feet of commercial office and retail space primarily
in Atlantic Canada.
Factors Contributing to Revenue Variance
Favourable
-- A 5.1% increase in RevPAR at the Hospitality Division, driven by
contribution from the Hilton Suites Winnipeg Airport hotel, which was
acquired in October 2011
-- Excluding the impact of the Hilton Suites Winnipeg Airport hotel, RevPAR
was $64.85 for the first quarter of 2012, an increase of 2.5% quarter
over quarter. RevPAR increased due to an overall 3.1% increase in the
average daily room rate, partially offset by an overall 0.6% decrease in
hotel occupancy. The average daily room rate increased in all regions.
Hotel occupancy in Atlantic Canada and central Canada decreased, while
occupancy in western Canada increased.
Factors Contributing to Earnings Variance
Favourable
-- Contribution from the Hilton Suites Winnipeg Airport hotel
Unfavourable
-- A $0.5 million gain on the sale of the Viking Mall during the first
quarter of 2011
CORPORATE AND OTHER(1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 6 6 -
Operating Expenses 3 2 1
Depreciation and Amortization 1 1 -
Other Income (Expenses), Net (5) - (5)
Finance Charges 11 14 (3)
Income Tax Recovery (4) (3) (1)
----------------------------------------------------------------------------
(10) (8) (2)
Preference Share Dividends 11 11 -
----------------------------------------------------------------------------
Net Corporate and Other Expenses (21) (19) (2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 non-regulated wholly owned subsidiary
FortisBC Alternative Energy Services Inc. and FHI's 30% ownership
interest in CustomerWorks Limited Partnership ("CWLP"). The contracts
between CWLP and the FortisBC Energy companies ended on December 31,
2011.
Factors Contributing to Net Corporate and Other Expenses Variance
Unfavourable
-- Increased other expenses, net of other income, driven by approximately
$4 million of costs incurred in the first quarter of 2012 related to the
pending acquisition of CH Energy Group and an approximate $1.5 million
foreign exchange loss associated with the translation of the US dollar-
denominated long-term other asset representing the book value of the
Corporation's former investment in Belize Electricity
Favourable
-- Lower finance charges primarily due to: (i) higher capitalized interest
associated with the financing of the construction of the Corporation's
51% controlling ownership interest in the Waneta Expansion; (ii) lower
credit facility borrowings due to the repayment of borrowings during the
third quarter of 2011 with a portion of the proceeds from the public
common equity offering in mid-2011; and (iii) the conversion of the
Corporation's US$40 million unsecured convertible subordinated
debentures into common shares in November 2011
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the first quarter of 2012 are summarized as follows.
NATURE OF REGULATION
----------------------------------------------------------------------------
Allowed Returns (%) Supportive
Features
----------------
Regulated Regulatory Allowed 2010 2011 2012 Future or
Utility Authority Common Historical Test
Equity Year
(%) Used to Set
Customer Rates
----------------------------------------------------------------------------
ROE COS/ROE
---------------------------
FEI British 40 9.50 9.50 9.50 FEI: Prior to
Columbia January 1, 2010,
Utilities 50/50
Commission sharing of
("BCUC") earnings above
or below
the allowed ROE
under a PBR
mechanism that
expired on
December 31,
2009 with a two-
year
phase-out
FEVI BCUC 40 10.00 10.00 10.00
FEWI BCUC 40 10.00 10.00 10.00 ROEs established
by the BCUC
----------------
Future Test Year
----------------------------------------------------------------------------
FortisBC BCUC 40 9.90 9.90 9.90 COS/ROE
Electric
PBR mechanism
for 2009 through
2011: 50/50
sharing of
earnings
above or below
the allowed ROE
up
to an achieved
ROE that is 200
basis
points above or
below the
allowed
ROE - excess to
deferral account
ROE established
by the BCUC
----------------
Future Test Year
----------------------------------------------------------------------------
Fortis- Alberta 41 9.00 8.75 8.75 COS/ROE
Alberta Utilities
Commission
("AUC") ROE established
by the AUC
----------------
Future Test Year
----------------------------------------------------------------------------
Newfound- Newfoundland 45 9.00 +/- 8.38 +/- 8.38 +/- COS/ROE
land and 50 bps 50 bps (1)
Power Labrador 50 bps The allowed ROE
Board of is set using an
Commissioners automatic
of adjustment
Public formula tied
Utilities to long-term
("PUB") Canada bond
yields. The
formula has been
suspended for
2012.
----------------
Future Test Year
----------------------------------------------------------------------------
Maritime Island 40 9.75 9.75 9.75 COS/ROE
Electric Regulatory
and
Appeals
Commission
("IRAC")
----------------
Future Test Year
----------------------------------------------------------------------------
Fortis- Ontario Canadian Niagara
Ontario Energy Power - COS/ROE
Electric Board
("OEB")
Canadian 40 8.01 8.01 8.01(2) Algoma Power -
Niagara COS/ROE and
Power subject to Rural
and Remote Rate
Protection
("RRRP") Program
Algoma 40 8.57 9.85 9.85(2)
Power
Franchise Cornwall
Agreement Electric - Price
Cornwall cap with
Electric commodity cost
flow through
----------------
Canadian Niagara
Power - 2009
historical test
year for 2010,
2011
and 2012
Algoma Power -
2007 historical
test
year for 2010;
2011 test year
for 2011
and 2012
----------------------------------------------------------------------------
Caribbean Electricity N/A 7.75 - 7.75 - 7.25 - COS/ROA
Utilities Regulatory 9.75 9.75 9.25
Authority Rate-cap
("ERA") adjustment
mechanism
("RCAM") 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(3) 17.50(3) 17.50(3) COS/ROA
Turks make
and annual
Caicos filings
to the
Interim
Government
of the Turks
and Caicos
Caicos
Islands
("Interim
Government")
If the actual
ROA is lower
than the allowed
ROA, due to
additional costs
resulting from a
hurricane or
other event, the
Company may
apply for an
increase in
customer rates
in the following
year.
----------------
Future Test Year
----------------------------------------------------------------------------
(1) Interim, pending the review of Newfoundland Power's cost of capital in
2012 by the PUB
(2) Based on the ROE automatic adjustment formula, the allowed ROE for
electric utilities in Ontario is 9.12% for utilities with rates
effective May 1, 2012. This ROE is not applicable to regulated electric
utilities in Ontario until they are scheduled to file their next full
COS rate applications. As a result, the allowed ROE of 9.12% is not
applicable to Canadian Niagara Power or Algoma Power for 2012.
(3) Amount provided under licence. ROA achieved in 2010 and 2011 was
significantly lower than the ROA allowed under the licence due to
significant investment occurring at the utility and the lack of rate
relief thereto.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
----------------------------------------------------------------------------
Regulated Summary Description
Utility
----------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review with the BCUC natural gas and propane
commodity prices every three months and midstream costs
annually, in order to ensure the flow-through rates charged
to customers are sufficient to cover the cost of purchasing
natural gas and propane and contracting for midstream
resources, such as third-party pipeline and/or storage
capacity. The commodity cost of natural gas and propane and
midstream costs are flowed through to customers without
markup. The bundled rate charged to FEVI customers includes a
component to recover approved gas costs and is set annually.
In order to ensure that the balance in the Commodity Cost
Reconciliation Account is recovered on a timely basis, FEI
and FEWI prepare and file quarterly calculations with the
BCUC to determine whether customer rate adjustments are
needed to reflect prevailing market prices for natural gas.
These rate adjustments ignore the temporal effect of
derivative valuation adjustments on the balance sheet and,
instead, reflect the forward forecast of gas costs over the
recovery period.
- Effective January 1, 2012, interim rates for residential
customers in the Lower Mainland, Fraser Valley and Interior,
North and Kootenay service areas increased by approximately
3% and interim rates for FEWI's residential customers
increased by approximately 6%, reflecting changes in delivery
and midstream costs. Interim approval was also received to
hold FEVI customer rates at 2011 levels, effective January 1,
2012. Natural gas commodity rates were unchanged, effective
January 1, 2012.
- Effective April 1, 2012, due to a decrease in natural gas
commodity rates, rates for residential customers in the Lower
Mainland, Fraser Valley and Interior, North and Kootenay
service areas decreased by approximately 10% and rates for
residential customers at FEWI decreased approximately 6%,
following the BCUC's quarterly review of commodity costs.
- In July 2011 FEVI received a BCUC decision approving the
option for two First Nations bands to invest up to a combined
15% in the equity component of the capital structure of the
liquefied natural gas ("LNG") storage facility on Vancouver
Island. In late 2011 each band exercised its option and each
invested approximately $6 million in equity in the LNG
storage facility on January 1, 2012.
- In October 2011 FEI filed an application for approval of
expenditures of approximately $5 million on facilities
required to provide thermal energy services to 19 buildings
in the Delta School District located in the Greater Vancouver
area and to provide thermal energy upgrades to the buildings
over the next two years. When completed, FEI will own,
operate and maintain the new thermal plants and charge the
Delta School District a single rate for thermal energy
consumed. In March 2012 the BCUC issued its decision granting
FEI a Certificate of Public Convenience and Necessity
("CPCN") related to the capital expenditures, on the
condition that FEI assign the related third-party contracts
associated with the above-noted project to a regulated
company affiliated with FEI, which FEI has complied with.
Approval of the related customer rates and rate design, as
filed by FEI, were denied and the Company refiled revised
rates and rate design in April 2012, as invited by the BCUC,
with a decision pending from the BCUC.
- In February 2012 the BCUC approved FEI's amended
application for a general tariff for the provision of
compressed natural gas ("CNG") and LNG for transportation
vehicles. In February 2012 FEI subsequently filed for a CPCN
to construct and operate CNG fueling station infrastructure,
to be in service October 2012, along with a long-term
contract with a counterparty for the supply of CNG in
accordance with the approved general tariff. A decision on
the above matter is expected in May 2012.
- In November 2011 FEI, FEVI and FEWI filed an application
with the BCUC for the amalgamation of the three companies
into one legal entity and for the implementation of common
rates and services for the utilities' customers across
British Columbia, effective January 1, 2013. In late 2011 the
utilities temporarily suspended their application while they
provide additional information to the BCUC, as requested. In
April 2012 the utilities refiled their application. The
amalgamation requires approval by the BCUC and consent of the
Government of British Columbia.
- In November 2011 the BCUC issued preliminary notification
to public utilities subject to its regulation, including the
FortisBC gas and electric utilities, that it planned to
initiate a Generic Cost of Capital ("GCOC") Proceeding in
early 2012. In February 2012 the BCUC established that a GCOC
Proceeding would take place and, in March 2012, provided for
comment a preliminary scoping document outlining the matters
to be examined by the proceeding. In April 2012 the BCUC
issued a final scoping document identifying the items that
will be reviewed as part of the GCOC Proceeding, which
include: (i) the appropriate cost of capital for a benchmark
low-risk utility effective January 1, 2013, which includes
capital structure, ROE and interest on debt; (ii) the
establishment of a benchmark ROE based on a benchmark low-
risk utility effective from January 1, 2013 through December
31, 2013 for the initial transition year; (iii) the
determination of whether a return to an ROE automatic
adjustment mechanism is warranted, which would be implemented
January 1, 2014 or, if not, a future regulatory process will
be set to review the ROE for a benchmark low-risk utility
beyond December 31, 2013; (iv) a generic methodology on how
to establish each utility's cost of capital in reference to
the cost of capital for a benchmark low-risk utility; (v) a
methodology to establish a deemed capital structure and
deemed cost of capital, particularly for those utilities
without third-party debt; and (vi) for those utilities that
require a deemed interest rate, a methodology to establish a
deemed interest rate automatic adjustment mechanism and, if
not warranted, a future regulatory process will be set on how
the deemed interest rate would be adjusted beyond December
31, 2013. The GCOC Proceeding is not intended to set each
utility's risk premium. As part of the GCOC Proceeding, the
BCUC will retain an independent consultant to report on
regulatory practices in Canadian jurisdictions. The GCOC
Proceeding will occur in 2012. The result of the GCOC
Proceeding could materially impact the earnings of the
FortisBC Energy Companies and FortisBC Electric.
- In April 2012 the BCUC issued its decision on the FortisBC
Energy companies' 2012-2013 RRAs. The interim increases in
customer rates, effective January 1, 2012, at FEI and FEWI
reflected the applied for rate increases. The above-noted
decision is expected to result in a decrease in customer
delivery rates at FEI and FEWI in the range of 1%-2% from the
interim rates. In its decision, the BCUC approved FEVI's 2012
and 2013 customer rates to remain unchanged from 2011
customer rates. The difference between interim and final
customer rates at FEI and FEWI will be refunded to customers
over the remainder of 2012. The final approved customer
delivery rates reflect allowed ROEs and capital structure
unchanged from 2011. The final rate increases were driven by
ongoing investment in energy infrastructure focused on system
integrity and reliability, and forecasted increased operating
expenses associated with inflation, a heightened focus on
safety and security of the natural gas system, and increasing
compliance with codes and regulations.
----------------------------------------------------------------------------
FortisBC - In June 2011 FortisBC Electric filed its 2012-2013 RRA,
Electric which included its 2012-2013 Capital Expenditure Plan and its
Integrated System Plan ("ISP"). The ISP includes the
Company's Resource Plan, Long-Term Capital Plan and Long-Term
Demand Side Management Plan. FortisBC Electric requested an
interim 4% increase in customer electricity rates effective
January 1, 2012 and a 6.9% increase effective January 1,
2013. The rate increases are due to ongoing investment in
energy infrastructure, including increased costs of financing
the investment, as well as increased purchased power costs.
The requested customer rates reflect an allowed ROE and
capital structure unchanged from 2011. In addition to a
continuation of deferral accounts and flow-through treatments
that existed under the PBR agreement, which expired at the
end of 2011, the 2012-2013 RRA proposes deferral accounts and
flow-through treatment for variances from the forecast used
to set customer rates for electricity revenue, purchased
power costs and certain other costs.
- In November 2011 FortisBC Electric filed an updated 2012-
2013 RRA to include updated financial estimates and
forecasts, resulting in a revised requested increase in
customer rates of 1.5%, effective January 1, 2012, and 6.5%,
effective January 1, 2013. The revised application assumes
forecast midyear rate base of approximately $1,146 million
for 2012 and $1,215 million for 2013. An oral hearing process
occurred in March 2012 and a decision is expected mid-2012.
The interim, refundable customer rate increase of 1.5%,
effective January 1, 2012, was approved by the BCUC pending a
final decision on the Company's 2012-2013 RRA.
- In November 2011 FortisBC Electric executed an agreement to
purchase capacity from the Waneta Expansion. The agreement
allows FortisBC Electric to purchase capacity over 40 years
upon completion of the Waneta Expansion, which is expected to
be in spring 2015. The form of the agreement was originally
accepted for filing by the BCUC in September 2010. The BCUC
is conducting its usual review process of the executed
agreement, filed in November 2011, to determine whether a
hearing is necessary to decide whether the agreement is in
the public interest.
- In March 2012 the BCUC issued an order establishing a
written hearing process to review the prudency of
approximately $29 million in capital expenditures incurred
related to the Kettle Valley Distribution Source Project,
which was substantially completed in 2009. FortisBC Electric
believes that the capital expenditures were prudently
incurred and, therefore, cannot reasonably determine if any
of such expenditures may be disallowed from rate base and any
resulting financial impact. The hearing is expected to take
place throughout 2012.
----------------------------------------------------------------------------
FortisAlberta - In October 2010 the Central Alberta Rural Electrification
Association ("CAREA") filed an application with the AUC
requesting that, effective January 1, 2012, CAREA be entitled
to service any new customers wishing to obtain electricity
for use on property overlapping CAREA's service area and that
FortisAlberta be restricted to providing service in the CAREA
service area only to those customers who are not being
provided service by CAREA. FortisAlberta intervened in the
proceeding to oppose CAREA's request, with an oral argument
heard in April 2012. A decision on this matter is expected
during the third quarter of 2012.
- In 2010 the AUC initiated a process to reform utility rate
regulation for distribution utilities in Alberta. The AUC
intends to introduce PBR-based distribution service rates
beginning in 2013 for a five-year term, with 2012 to be used
as the base year. In July 2011 FortisAlberta, along with
other distribution utilities operating under the AUC's
jurisdiction, submitted PBR proposals to the AUC. The
Company's submission outlines its views as to how PBR should
be implemented at FortisAlberta. A hearing on the matter
commenced in April 2012 with a decision expected in 2012.
- In December 2011 the AUC issued its decision on its 2011
GCOC Proceeding, establishing the allowed ROE at 8.75% for
2011 and 2012 and, on an interim basis, at 8.75% for 2013.
The equity component of FortisAlberta's capital structure
remains at 41% and will continue at that level until changed
by any future order of the AUC. The AUC concluded that it
would not return to a formula-based ROE automatic adjustment
mechanism at this time and that it would initiate a
proceeding in due course to establish a final allowed ROE for
2013 and revisit the matter of a return to a formula-based
approach in future periods.
- In January 2012 FortisAlberta and other distribution
utilities in Alberta filed motions for leave to appeal with
the Alberta Court of Appeal with respect to the 2011 GCOC
decision, challenging certain pronouncements made by the AUC
as being incorrect regarding cost responsibility for stranded
assets. In February 2012 FortisAlberta and other utilities
filed requests for the AUC to review and vary its
pronouncements.
- In April 2012 the AUC approved, substantially as filed, an
NSA pertaining to FortisAlberta's 2012 distribution revenue
requirements resulting in an average increase in customer
rates of approximately 5%, effective January 1, 2012,
consistent with the interim rate increase that was previously
approved by the AUC in December 2011. The increase in
customer rates was driven primarily by ongoing investment in
energy infrastructure, including increased depreciation and
financing costs. The NSA provides for forecast midyear rate
base of $2,025 million. The AUC did not approve the
continuation of the deferral of volume variances associated
with FortisAlberta's Alberta Electric System Operator
("AESO") charges deferral account. This item is to be
examined by the AUC in a future proceeding.
----------------------------------------------------------------------------
Newfoundland - In March 2012 Newfoundland Power filed a Cost of Capital
Power Application with the PUB to discontinue the use of the
current ROE automatic adjustment mechanism and to approve a
just and reasonable rate of return on average rate base for
2012. A public hearing on the application is currently
scheduled for June 2012.
- Newfoundland Power expects to file a Rate Stabilization
Account ("RSA") application with the PUB by the end of May
2012 to seek an average increase in customer electricity
rates of approximately 7%, effective July 1, 2012. The
expected increase in rates is primarily due to the result of
the normal annual operation of Newfoundland and Labrador
Hydro's ("Newfoundland Hydro") Rate Stabilization Plan.
Variances in the cost of fuel used to generate electricity
that Newfoundland Hydro sells to Newfoundland Power are
captured and flowed through to customers through the
operation of Newfoundland Power's RSA. The increase in rates,
principally due to higher fuel prices, will not have an
impact on Newfoundland Power's earnings.
- The Company is currently assessing its requirement to file
a general rate application with the PUB to recover expected
increased costs in 2013.
----------------------------------------------------------------------------
Maritime - In February 2012 the PEI Energy Commission (the "PEI
Electric Commission") released its Discussion Paper "Charting Our
Electricity Future", which outlined discussion points the PEI
Commission is seeking input on through a consultative process
with stakeholders and the general public. These discussion
points included: (i) electricity ownership and management on
PEI and whether Maritime Electric is doing a good job of
balancing safety and reliability with cost of service; (ii)
the future role of IRAC, the PEI Energy Corporation and the
PEI Office of Energy Efficiency; (iii) a new cable
interconnection; (iv) the treatment of the financing of the
$47 million of deferred incremental replacement energy costs
associated with the Point Lepreau nuclear generating station;
(v) regional energy collaboration; (vi) demand-side
management; (vii) renewable energy and environmental
stewardship; and (viii) potential options for natural gas-
generated electricity. Public forums and stakeholder
consultations occurred in February and March 2012, in which
Maritime Electric was a participant. The PEI Commission is
expected to release a final report of its recommendations to
the Government of PEI in fall 2012.
- In March 2012 Maritime Electric received regulatory
approval to defer, for refund to customers in a future period
to be determined, contingent income tax expense reductions
associated with the Company's amendment of corporate income
tax filings for the years 2007 through 2010. The amended
filings seek to expense certain costs previously capitalized
for income tax purposes.
- Maritime Electric intends to file an application with IRAC
in fall 2012 for 2013 customer rates and allowed ROE.
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FortisOntario - In non-rebasing years, customer electricity distribution
rates are set using inflationary factors less an efficiency
target under the Third-Generation Incentive Rate Mechanism
("IRM") as prescribed by the OEB. In the first quarter of
2012, the OEB published applicable inflationary and
efficiency targets, resulting in minimal changes in base
customer electricity distribution rates at FortisOntario's
operations in Fort Erie, Gananoque and Port Colborne
effective May 1, 2012. The Third-Generation IRM maintains the
allowed ROE at 8.01% for 2012.
- In April 2012 the OEB issued Final Decisions and Orders for
customer rates effective May 1, 2012 at FortisOntario's
operations in Fort Erie, Gananoque and Port Colborne. The
result was an average 3.1% decrease in residential customer
rates in Fort Erie, an average 0.6% increase in residential
customer rates in Gananoque, and an average 4.6% decrease in
residential customer rates in Port Colborne. The above-noted
rate changes were mainly due to changes in rate riders
associated with regulatory deferral accounts and smart meter
funding.
- In April 2011 FortisOntario provided the City of Port
Colborne and Port Colborne Hydro with an irrevocable written
notice of FortisOntario's election to exercise the purchase
option, under the current operating lease agreement, at the
purchase option price of approximately $7 million on April
15, 2012. The purchase constitutes the sale of the remaining
assets of Port Colborne Hydro to FortisOntario. The purchase
transaction was approved by the OEB in March 2012 and closed
on April 16, 2012.
- In March 2012 the OEB issued its decision on Algoma Power's
Third-Generation IRM application for customer electricity
distribution rates, effective January 1, 2012. The decision
approved a price-cap index of 2.81% for customers subject to
RRRP funding and 0.38% for those customers not subject to
RRRP funding. RRRP funding for 2012 has been set at
approximately $11 million. Algoma Power's allowed ROE is
maintained at 9.85% for 2012.
- FortisOntario expects to file a COS Application in 2012 for
harmonized electricity distribution rates in Fort Erie, Port
Colborne and Gananoque, effective January 1, 2013, using a
2013 forward test year. The timing of the filing of the COS
Application corresponds with the ending of the period that
the current Third-Generation IRM applies to FortisOntario.
----------------------------------------------------------------------------
Caribbean - In April 2012 the ERA approved Caribbean Utilities' 2012-
Utilities 2016 Capital Investment Plan ("CIP") for US$122 million of
non-generation installation capital expenditures. The
remaining US$62 million of the 2012-2016 CIP relates to new
generation installation, which would be subject to a
competitive solicitation process with the next generation
unit scheduled for installation in 2014. The 2012-2016 CIP
was prepared in line with the Certificate of Need that was
filed with the ERA in November 2011, which included 18 MW of
generating capacity to be installed in either 2015 or 2016,
contingent on load growth over the next two years.
- In March 2012 the ERA approved the creation of Caribbean
Utilities' wholly owned subsidiary DataLink, Ltd.
("DataLink"). Subsequently, the Information and
Communications Technology Authority ("ICTA") granted a
licence to DataLink to provide fibre optic infrastructure on
Grand Cayman. The ICTA licence allows DataLink to assume full
responsibility for existing pole attachment agreements and
optical fibre lease agreement currently held by Caribbean
Utilities with third-party information and communications
technology service providers.
- In December 2011 Caribbean Utilities conducted and
completed a competitive bidding process to fill up to 13 MW
of non-firm renewable energy capacity. Two renewable energy
developers have been chosen to commence discussions with
Caribbean Utilities to provide energy to the utility's grid.
The proposals being considered are two 5-MW solar
photovoltaic power plants and one 3-MW small-scale wind
turbine project. Caribbean Utilities and the developers are
expected to commence negotiations related to power purchase
agreements. The power purchase agreements, however, are
subject to ERA review and approval.
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Fortis Turks - An independent review of the regulatory framework for the
and Caicos electricity sector in the Turks and Caicos Islands was
performed during the third quarter of 2011 on behalf of the
Interim Government. The purpose of the review was to: (i)
assess the effectiveness of the current regulatory framework
in terms of its administrative and economic efficiency; (ii)
assess the current and proposed electricity costs and tariffs
in the Turks and Caicos Islands in relation to comparable
regional and international utilities; (iii) make
recommendations for a revised regulatory framework and
Electricity Ordinance; and (iv) make recommendations for the
implementation and operation of the revised regulatory
framework. Fortis Turks and Caicos provided a comprehensive
response to the Interim Government in January 2012 stating
that the Company supports limited mutually agreed upon
reforms, but that its current licences must be respected and
can only be changed by mutual consent. Specifically, Fortis
Turks and Caicos would support reforms that strengthen the
role of the regulator in the rate-setting process and that
are fair to all stakeholders. Negotiations between Fortis
Turks and Caicos and the Interim Government are expected to
commence mid-2012 with implementation of any resulting
changes in the regulatory framework expected to occur at the
end of 2012.
- In February 2012 the Interim Government approved an
approximate 26% increase in electricity rates, effective
April 1, 2012, for Fortis Turks and Caicos' large hotel
customers. In addition, other qualitative enhancements to the
franchise were also achieved, including: (i) improved wording
in the Electricity Rate Regulation; (ii) an approved increase
in kilowatt hour consumption thresholds for both medium and
large hotels; (iii) an expansion of service territory to
cover all of the Caicos Islands, except for areas currently
serviced by private suppliers' licences, with new 25-year
licenses issued for the expanded service territory; and (iv)
the discontinuance of the government subsidization of the
utility's South Caicos operations.
- In March 2012 Fortis Turks and Caicos submitted its 2011
annual regulatory filing outlining the Company's performance
in 2011. Included in the filing were the calculations, in
accordance with the utility's licence, of rate base of US$166
million for 2011 and cumulative shortfall in achieving
allowable profits of US$72 million as at December 31, 2011.
- In April 2012 Fortis Turks and Caicos entered into a
Streetlight Takeover Agreement with the Interim Government
whereby the responsibility for the ownership, installation
and maintenance of all streetlights in the utility's service
territory was transferred to Fortis Turks and Caicos.
----------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between March 31, 2012 and December 31, 2011.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
March 31, 2012 and December 31, 2011
---------------------------------------------------------------------------
Balance Sheet Increase/ Explanation
Account (Decrease)
($ millions)
---------------------------------------------------------------------------
Accounts 58 The increase was primarily due to the impact
receivable of a seasonal increase in sales, and the
operation of the equal payment plans for
customers, mainly at the FortisBC Energy
companies and Newfoundland Power.
---------------------------------------------------------------------------
Inventories (58) The decrease was driven by the normal
seasonal reduction of gas in storage at the
FortisBC Energy companies, due to higher
consumption during the winter months.
---------------------------------------------------------------------------
Utility capital 96 The increase primarily related to $211
assets million invested in electricity and gas
systems, partially offset by depreciation and
customer contributions for the three months
ended March 31, 2012.
---------------------------------------------------------------------------
Short-term (83) The decrease was driven by lower borrowings
borrowings at the FortisBC Energy companies due to
seasonality of operations.
---------------------------------------------------------------------------
Regulatory 70 The increase was driven by deferrals at the
liabilities - FortisBC Energy companies associated with an
current and increase in the Rate Stabilization Deferral
long-term Account at FEVI, reflecting amounts collected
in customer rates in excess of the cost of
providing service during the three months
ended March 31, 2012, and an increase in the
Midstream Cost Reconciliation Account, as
amounts collected in customer rates were in
excess of actual midstream gas-delivery costs
for the three months ended March 31, 2012.
---------------------------------------------------------------------------
Shareholders' 78 The increase was primarily due to net
equity (before earnings attributable to common equity
non- shareholders for the three months ended March
controlling 31, 2012, less common share dividends, and
interests) the issuance of common shares under the
Corporation's dividend reinvestment plan.
---------------------------------------------------------------------------
Non-controlling 38 The increase was driven by advances from the
interests 49% non-controlling interests in the Waneta
Expansion Limited Partnership ("Waneta
Partnership") and an approximate $12 million,
or 15%, equity investment by two First
Nations bands in the LNG storage facility on
Vancouver Island.
---------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the three months ended March 31, 2012, as compared to the same period in
2011, followed by a discussion of the nature of the variances in cash flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows
(Unaudited) Quarter Ended March 31
($ millions) 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of Period 87 107 (20)
Cash Provided by (Used in):
Operating Activities 328 302 26
Investing Activities (211) (217) 6
Financing Activities (94) (108) 14
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Cash, End of Period 110 84 26
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Operating Activities: Cash flow from operating activities, after working
capital adjustments, was $26 million higher quarter over quarter largely due to
favourable changes in working capital mainly associated with current regulatory
deferral accounts at the FortisBC Energy companies and FortisAlberta, and higher
earnings. The above-noted increases were partially offset by unfavourable
changes in accounts receivable, inventories and long-term regulatory deferral
accounts.
Investing Activities: Cash used in investing activities was comparable quarter
over quarter. Lower capital spending at the regulated utilities in western
Canada and the Caribbean was largely offset by an increase in capital spending
related to the non-regulated Waneta Expansion.
Financing Activities: Cash used in financing activities was $14 million lower
for the quarter compared to the same quarter last year. The decrease was due to
higher advances from non-controlling interests and lower repayments of
short-term borrowings, partially offset by: (i) higher common share dividends;
(ii) lower proceeds from the issuance of common shares; and (iii) lower net
borrowings under committed credit facilities classified as long term.
Net repayment of short-term borrowings was $83 million for the quarter compared
to $98 million for the same quarter last year. The change quarter over quarter
was driven by the FortisBC Energy companies.
Net borrowings under committed credit facilities for the first quarter of 2012
compared to the same quarter of 2011 are summarized in the following table.
----------------------------------------------------------------------------
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
($ millions) 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta (29) 12 (41)
FortisBC Electric (9) - (9)
Newfoundland Power 14 13 1
Corporate 31 (10) 41
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Total 7 15 (8)
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----------------------------------------------------------------------------
Borrowings under credit facilities by the utilities are primarily in support of
their capital expenditure programs and/or for working capital requirements.
Repayments are primarily financed through the issuance of long-term debt, cash
from operations and/or equity injections from Fortis. From time to time,
proceeds from preference share, common share and long-term debt offerings are
used to repay borrowings under the Corporation's committed credit facility.
Advances of approximately $29 million were received in the first quarter of 2012
from non-controlling interests in the Waneta Partnership to finance capital
spending related to the Waneta Expansion compared to $17 million received in the
first quarter of 2011. In January 2012 advances of approximately $12 million
were received from two First Nations bands representing their 15% equity
investment in the LNG storage facility on Vancouver Island.
Proceeds from the issuance of common shares decreased $9 million quarter over
quarter, reflecting a lower number of stock options exercised under the
Corporation's stock option plans.
Common share dividends paid during the first quarter of 2012 were $44 million,
net of $13 million in dividends reinvested, compared to $35 million, net of $16
million in dividends reinvested, paid during the same quarter of 2011. The
dividend paid per common share for the first quarter of 2012 was $0.30 compared
to $0.29 for the first quarter of 2011. The weighted average number of common
shares outstanding for the first quarter was 189.0 million compared to 175.0
million for the first quarter of 2011.
CONTRACTUAL OBLIGATIONS
As at March 31, 2012, consolidated contractual obligations of Fortis over the
next five years and for periods thereafter are outlined in the following table.
A detailed description of the nature of the obligations is provided in the 2011
Annual MD&A and below, where applicable. The presentation of certain contractual
obligations has changed from that provided in the 2011 Annual MD&A due to the
adoption of US GAAP. For further information concerning these changes, refer to
the 2011 audited consolidated financial statements prepared in accordance with
US GAAP and voluntarily filed on SEDAR.
----------------------------------------------------------------------------
Contractual Obligations
(Unaudited) Due Due in Due in Due
As at March 31, 2012 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 5,901 121 768 428 4,584
Capital lease
obligations(1) 2,501 42 86 89 2,284
Waneta Partnership
promissory note 72 - - - 72
Gas purchase contract
obligations(2) 217 130 87 - -
Power purchase obligations
FortisBC Electric 25 12 10 3 -
FortisOntario 399 41 99 103 156
Maritime Electric 176 42 79 41 14
Capital cost 457 17 36 36 368
Joint-use asset and share
service agreements 64 4 8 7 45
Operating lease
obligations 155 20 36 34 65
Defined benefit pension
funding contributions(3) 111 40 46 22 3
Other 8 1 2 1 4
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Total 10,086 470 1,257 764 7,595
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(1) Includes principal payments and approximately $2 million of imputed
interest and executory costs, mainly related to FortisBC Electric's
Brilliant Power Purchase Agreement and Brilliant Terminal Station.
(2) Based on index prices as at March 31, 2012
(3) Consolidated defined benefit pension funding contributions include
current service, solvency and special funding amounts. The
contributions are based on estimates provided under the latest
completed actuarial valuations, which generally provide funding
estimates for a period of three to five years from the date of the
valuations. As a result, actual pension funding contributions may be
higher than these estimated amounts, pending completion of the next
actuarial valuations for funding purposes, which are expected to be
performed as of the following dates for the larger defined benefit
pension plans:
December 31, 2012 FortisBC Energy companies (covering non-unionized
employees)
December 31, 2013 FortisBC Energy companies (covering unionized
employees)
December 31, 2013 FortisBC Electric
December 31, 2014 Newfoundland Power
The estimate of defined benefit pension funding contributions in the
above table includes the impact of the outcome of the December 31, 2011
actuarial valuation, completed in April 2012, associated with the
defined benefit pension plan at Newfoundland Power. As a result of the
valuation, Newfoundland Power is required to fund a solvency deficiency
of approximately $53.5 million, including interest, over five years
beginning in 2012, which is included in the above table.
Other contractual obligations, which are not reflected in the above table, did
not materially change from those disclosed in the 2011 Annual MD&A, except as
described below.
In January 2012 two First Nations bands each invested approximately $6 million
in equity in the Mount Hayes LNG storage facility, representing a 15% equity
interest in the Mount Hayes Limited Partnership, with FEVI holding the
controlling 85% ownership interest. The non-controlling interests hold put
options, which, if exercised, would require FEVI to repurchase the 15% ownership
interest for cash, in accordance with the terms of the partnership agreement.
For a discussion of the nature and amount of the Corporation's consolidated
capital expenditure program, which is not included in the Contractual
Obligations table above, refer to the "Capital Expenditure Program" section of
this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to allow the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt offerings. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40%
equity, including preference shares, and 60% debt, as well as investment-grade
credit ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in each of
the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
March 31, 2012 December 31, 2011
($ millions) (%) ($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
obligations (net of
cash)(1)(2) 6,186 56.2 6,296 57.1
Preference shares 912 8.3 912 8.3
Common shareholders' equity 3,901 35.5 3,823 34.6
----------------------------------------------------------------------------
Total(3) 10,999 100.0 11,031 100.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes long-term debt and capital lease obligations, including
current portion, and short-term borrowings, net of cash
(2) Excluding capital lease obligations and financing obligations under
lease-in lease-out transactions, the debt component of the capital
structure was 54.4% as at March 31, 2012 and 55.3% as at December 31,
2011.
(3) Excludes amounts related to non-controlling interests
The improvement in the capital structure was primarily due to: (i) lower
short-term borrowings; (ii) net earnings attributable to common equity
shareholders, net of dividends; (iii) an increase in cash; and (iv) common
shares issued under the Corporation's dividend reinvestment plan.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's A-/Credit Watch - Negative (unsecured debt credit
rating)
DBRS A(low)/Under Review - Developing Implications (unsecured
debt credit rating)
The above credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis. In February 2012, after the announcement by Fortis that it
had entered into an agreement to acquire CH Energy Group, DBRS placed the
Corporation's credit rating under review with developing implications.
Similarly, S&P placed the Corporation's credit rating on credit watch with
negative implications.
CAPITAL EXPENDITURE PROGRAM
Capital investment in infrastructure is required to ensure continued and
enhanced performance, reliability and safety of the gas and electricity systems
and to meet customer growth. All costs considered to be maintenance and repairs
are expensed as incurred. Costs related to replacements, upgrades and
betterments of capital assets are capitalized as incurred.
A breakdown of the $229 million in gross capital expenditures by segment for the
first quarter of 2012 is provided in the following table.
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited)(1)
Quarter Ended March 31, 2012
($ millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other
Regu- Regu-
lated Total lated
Elec- Regu- Elec-
tric lated tric Non-
FortisBC New- Utili- Utili- Utili- Regu-
Energy Fortis found- ties - ties - ties - lated - Fortis
Com- Alberta FortisBC land Cana- Cana- Carib- Utility Proper-
panies (2) Electric Power dian dian bean (3) ties Total
----------------------------------------------------------------------------
46 79 17 15 9 166 10 48 5 229
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(1) Relates to cash payments to acquire or construct utility capital
assets, income producing properties and intangible assets, as reflected
in the consolidated statement of cash flows. Includes non-ARO removal
expenditures, net of salvage proceeds, for those utilities where such
expenditures are permissible in rate base in 2012. Excludes capitalized
amortization and non-cash equity component of AFUDC.
(2) Includes payments made to AESO for investment in transmission-related
capital projects
(3) Includes non-regulated generation capital expenditures, mainly related
to the Waneta Expansion
Planned capital expenditures are based on detailed forecasts of energy demand,
weather, cost of labour and materials, as well as other factors, including
economic conditions, which could change and cause actual expenditures to differ
from forecasts.
There have been no material changes in the overall expected level, nature and
timing of the Corporation's significant capital projects from those that were
disclosed in the 2011 Annual MD&A. Gross consolidated capital expenditures for
2012 are forecasted at approximately $1.3 billion.
FEI's Customer Care Enhancement Project, at an estimated total project cost of
$110 million, came into service in January 2012. Approximately $25 million of
the project costs were incurred in the first quarter of 2012, mainly related to
final contractor payments, with a remaining $5 million expected to be incurred
in the second quarter of 2012.
Construction progress on the $900 million Waneta Expansion is going well and the
project is currently on schedule. Major construction activities on-site include
the completion of the excavation of the intake, powerhouse and power tunnels.
Approximately $290 million has been spent on the Waneta Expansion since
construction began late in 2010.
Over the five-year period 2012 through 2016, consolidated gross capital
expenditures are expected to be approximately $5.5 billion, consistent with that
disclosed in the 2011 Annual MD&A. Approximately 64% of the capital spending is
expected to be incurred at the regulated electric utilities, driven by
FortisAlberta and FortisBC Electric. Approximately 23% and 13% of the capital
spending is expected to be incurred at the regulated gas utilities and
non-regulated operations, respectively. Capital expenditures at the regulated
utilities are subject to regulatory approval. Over the five-year period, on
average annually, 39% of utility capital spending is expected to be incurred to
meet customer growth; 38% is expected to be incurred to ensure continued and
enhanced performance, reliability and safety of generation and T&D assets (i.e.,
sustaining capital expenditures); and 23% is expected to be incurred for
facilities, equipment, vehicles, information technology and other assets.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest
costs will generally be paid out of subsidiary operating cash flows, with
varying levels of residual cash flow available for subsidiary capital
expenditures and/or dividend payments to Fortis. Borrowings under credit
facilities may be required from time to time to support seasonal working capital
requirements. Cash required to complete subsidiary capital expenditure programs
is also expected to be financed from a combination of borrowings under credit
facilities, equity injections from Fortis and long-term debt offerings.
The Corporation's ability to service its debt obligations and pay dividends on
its common shares and preference shares is dependent on the financial results of
the operating subsidiaries and the related cash payments from these
subsidiaries. Certain regulated subsidiaries may be subject to restrictions that
may limit their ability to distribute cash to Fortis. Cash required of Fortis to
support subsidiary capital expenditure programs and finance acquisitions is
expected to be derived from a combination of borrowings under the Corporation's
committed credit facility and proceeds from the issuance of common shares,
preference shares and long-term debt. Depending on the timing of cash payments
from the subsidiaries, borrowings under the Corporation's committed credit
facility may be required from time to time to support the servicing of debt and
payment of dividends.
As at March 31, 2012, management expects consolidated long-term debt maturities
and repayments to average approximately $265 million annually over the next five
years. The combination of available credit facilities and relatively low annual
debt maturities and repayments provide the Corporation and its subsidiaries with
flexibility in the timing of access to capital markets.
As the hydroelectric assets and water rights of the Exploits River Hydro
Partnership ("Exploits Partnership") had been provided as security for the
Exploits Partnership term loan, the expropriation of such assets and rights by
the Government of Newfoundland and Labrador constituted an event of default
under the loan. The term loan is without recourse to Fortis and was
approximately $56 million as at March 31, 2012 (December 31, 2011 - $56
million). The lenders of the term loan have not demanded accelerated repayment.
The scheduled repayments under the term loan are being made by Nalcor Energy, a
Crown corporation, acting as agent for the Government of Newfoundland and
Labrador with respect to expropriation matters. For further information refer to
Note 35 to the Corporation's 2011 annual audited consolidated financial
statements prepared in accordance with US GAAP.
Except for the debt at the Exploits Partnership, as discussed above, Fortis and
its subsidiaries were in compliance with debt covenants as at March 31, 2012 and
are expected to remain compliant throughout the remainder of 2012.
CREDIT FACILITIES
As at March 31, 2012, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.2 billion, of which $2.0 billion was
unused, including $769 million unused under the Corporation's $800 million
committed revolving 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 $2.0 billion of the total credit facilities are
committed facilities with maturities ranging from 2013 through 2017.
The following summary outlines the credit facilities of the Corporation and its
subsidiaries.
----------------------------------------------------------------------------
Credit Facilities (Unaudited) As at
December
Corporate Regulated Fortis March 31, 31,
($ millions) and Other Utilities Properties 2012 2011
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Total credit
facilities 845 1,389 13 2,247 2,248
Credit facilities
utilized:
Short-term
borrowings - (73) (3) (76) (159)
Long-term debt
(including current
portion) (31) (50) - (81) (74)
Letters of credit
outstanding (1) (65) - (66) (66)
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Credit facilities
unused 813 1,201 10 2,024 1,949
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As at March 31, 2012 and December 31, 2011, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In March 2012 Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility, obtaining an extension to the maturity of
the facility to August 2017 from August 2015. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
In April 2012 FortisBC Electric renegotiated and amended its credit facility
agreement resulting in an extension to the maturity of the Company's $150
million unsecured committed revolving credit facility with $100 million now
maturing in May 2015 and $50 million now maturing in May 2013.
Fortis has requested an increase in the amount available for borrowing under its
committed corporate credit facility from $800 million to $1 billion, as
permitted under the credit facility agreement, and expects the increase to be
available in May 2012.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows.
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Financial Instruments
(Unaudited) As at
March 31, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Waneta Partnership
promissory note 45 50 45 49
Long-term debt, including
current portion 5,901 7,207 5,912 7,296
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The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a credit risk premium equal
to that of issuers of similar credit quality. Since the Corporation does not
intend to settle the long-term debt or promissory note prior to maturity, the
fair value estimate does not represent an actual liability and, therefore, does
not include exchange or settlement costs.
The financial instruments table above excludes the long-term other asset
associated with the Corporation's previous investment in Belize Electricity. The
fair value of the Corporation's expropriated investment in Belize Electricity
determined under the Government of Belize's valuation is significantly lower
than the fair value determined under the Corporation's independent valuation of
the utility. Due to uncertainty in the ultimate amount and ability of the
Government of Belize to pay compensation owing to Fortis for the expropriation
of Belize Electricity, the Corporation has recorded the long-term other asset at
the carrying value of the Corporation's previous investment in Belize
Electricity, including foreign exchange impacts, which was approximately $104
million as at March 31, 2012.
Risk Management: The Corporation's earnings from, and net investments in,
foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian
dollar exchange rate. The Corporation has effectively decreased the above
exposure through the use of US dollar borrowings at the corporate level. The
foreign exchange gain or loss on the translation of US dollar-denominated
interest expense partially offsets the foreign exchange loss or gain on the
translation of the Corporation's foreign subsidiaries' earnings, which are
denominated in US dollars. The reporting currency of Caribbean Utilities, Fortis
Turks and Caicos, FortisUS Energy Corporation and BECOL is the US dollar. Belize
Electricity's financial results were denominated in Belizean dollars, which are
pegged to the US dollar.
As at March 31, 2012, the Corporation's corporately issued US$550 million
(December 31, 2011 - US$550 million) long-term debt had been designated as an
effective hedge of the Corporation's foreign net investments. As at March 31,
2012, the Corporation had approximately US$8 million (December 31, 2011 - US$6
million) in foreign net investments remaining to be hedged. Foreign currency
exchange rate fluctuations associated with the translation of the Corporation's
corporately issued US dollar borrowings designated as effective hedges are
recorded in other comprehensive income and serve to help offset unrealized
foreign currency exchange gains and losses on the net investments in foreign
subsidiaries, which are also recorded in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with its previous
investment in Belize Electricity does not qualify for hedge accounting as Belize
Electricity is no longer a foreign subsidiary of Fortis. As a result, during
2011, a portion of corporately issued debt that previously hedged the former
investment in Belize Electricity was no longer an effective hedge. Effective
from June 20, 2011, foreign exchange gains and losses on the translation of the
asset associated with Belize Electricity and the corporately issued US
dollar-denominated debt that previously qualified as a hedge of the investment
were recognized in earnings. As a result, the Corporation recognized a foreign
exchange loss of approximately $1.5 million in earnings during the first quarter
of 2012.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes. As at March 31, 2012, the Corporation's derivative contracts
consisted of a foreign exchange forward contract, natural gas swap and option
contracts, and gas purchase contract premiums, all held by the FortisBC Energy
companies.
The following table summarizes the Corporation's derivative financial instruments.
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Derivative Financial Instruments (Unaudited) As at
March 31, December 31,
2012 2011
Carrying Carrying
(Liability) Number of Volume Value(1) Value(1)
Asset Maturity Contracts (petajoules)($ millions) ($ millions)
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Foreign exchange
forward
contract 2012 1 - - -
Fuel option
contracts 2012 - - - (1)
Natural gas
derivatives:
Swaps and
options 2014 90 51 (135) (135)
Gas purchase
contract
premiums 2014 27 99 3 -
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(1) Carrying value approximates fair value. The (liability) asset
represents the gross derivatives balance.
The foreign exchange forward contract is held by FEI to hedge the cash flow risk
related to approximately US$4 million remaining to be paid under a contract for
the implementation of a customer information system.
The fuel option contracts were held 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 matured in March 2012.
The natural gas derivatives are held by the FortisBC Energy companies and are
used to fix the effective purchase price of natural gas, as the majority of the
natural gas supply contracts have floating, rather than fixed, prices. The price
risk-management strategy of the FortisBC Energy companies aims to improve the
likelihood that natural gas prices remain competitive, to temper gas price
volatility on customer rates and to reduce the risk of regional price
discrepancies. As directed by the BCUC, FEI and FEVI suspended their commodity
hedging activities in 2011, which has continued into 2012, with the exception of
certain limited swaps. 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 foreign exchange forward contract and
natural gas derivatives are deferred as a regulatory asset or liability, subject
to regulatory approval, for recovery from, or refund to, customers in future
rates. The fair values of the derivative financial instruments were recorded in
accounts payable as at March 31, 2012 and as at December 31, 2011.
The fair value of the foreign exchange forward contract is calculated using the
present value of cash flows based on a market foreign exchange rate and the
foreign exchange forward rate curve. The fair value of the natural gas
derivatives is calculated using the present value of cash flows based on market
prices and forward curves for the commodity cost of natural gas. The fair values
of the foreign exchange forward contract and natural gas derivatives are
estimates of the amounts that would have to be received or paid 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 $66 million, as at March
31, 2012, the Corporation had no off-balance sheet arrangements, such as
transactions, agreements or contractual arrangements with unconsolidated
entities, structured finance entities, special purpose entities or variable
interest entities, that are reasonably likely to materially affect liquidity or
the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
There were no changes in the Corporation's significant business risks during the
first quarter of 2012 from those disclosed in the 2011 Annual MD&A, except for
those described below.
Regulatory Risk: In April 2012 regulatory decisions received for 2012 and 2013
customer gas delivery rates at the FortisBC Energy companies and for 2012
customer electricity distribution rates at FortisAlberta help to reduce
regulatory risk at the utilities. For further information, refer to the
"Material Regulatory Decisions and Applications" section of this MD&A.
Completion of the Acquisition of CH Energy Group: There is risk that some, or
all, of the expected benefits of the acquisition of CH Energy Group may fail to
materialize or may not occur within the time periods anticipated by the
Corporation. The realization of such benefits may be impacted by a number of
factors, many of which are beyond the control of Fortis.
Capital Resources and Liquidity Risk - Credit Ratings: In February 2012, after
the announcement by Fortis that it had entered into an agreement to acquire all
of the shares of CH Energy Group, DBRS placed the Corporation's credit rating
under review with developing implications. Similarly, S&P placed the
Corporation's credit rating on credit watch with negative implications.
FortisAlberta's existing debt credit rating by S&P was confirmed in January
2012, but was put on credit watch with negative implications in February 2012 as
a result of the Corporation's credit rating being placed on credit watch. During
the first quarter of 2012, DBRS confirmed FortisAlberta and Newfoundland Power's
existing debt credit ratings, and both DBRS and S&P confirmed Caribbean
Utilities' debt credit ratings.
Defined Benefit Pension Plan Assets: As at March 31, 2012, the fair value of the
Corporation's consolidated defined benefit pension plan assets was $821 million,
up $36 million or 4.6%, from $785 million as at December 31, 2011.
Labour Relations: The collective agreement between FortisBC Electric and the
Canadian Office and Professional Employees Union ("COPE"), Local 378, expired
January 31, 2011. An agreement expiring in March 2014 has been reached with
regard to certain customer service employees. Discussions continue with regard
to the remaining FortisBC Electric COPE bargaining unit.
The collective agreements between the FortisBC Energy companies and the
International Brotherhood of Electrical Workers ("IBEW"), Local 213, expired on
March 31, 2011. IBEW, Local 213, represents employees in specified occupations
in the areas of T&D. The parties are negotiating terms of a renewed collective
agreement.
The collective agreements between the FortisBC Energy companies and COPE, Local
378, expired on March 31, 2012. COPE, Local 378, represents employees in
specified occupations in the areas of administration and operations support. The
parties are negotiating the terms of a renewed collective agreement.
The two collective agreements between Newfoundland Power and IBEW, Local 1620,
expired on September 30, 2011. During the first quarter of 2012, one of the two
newly negotiated collective agreements was ratified. The other collective
agreement was not accepted and is now subject to ratification in May 2012. The
agreements are for three-year terms expiring in September 2014.
CHANGES IN ACCOUNTING POLICIES
Transition to US GAAP: Effective January 1, 2012, Fortis retroactively adopted
US GAAP with the restatement of comparative reporting periods. The areas of most
significant financial statement impacts upon adopting US GAAP include, but are
not limited to the: (i) recognition of the funded status of defined benefit
pension plans on the consolidated balance sheet and the inability to recognize
regulatory assets or liabilities associated with other post-employment benefit
("OPEB") costs that are recovered on a cash basis; (ii) recognition of the
Brilliant Power Purchase Agreement as a capital lease at FortisBC Electric;
(iii) recognition of lease-in lease-out transactions at the FortisBC Energy
companies as financing transactions with the corresponding assets recognized as
utility capital assets and the sales proceeds accounted for as long-term debt;
(iv) reclassification of preference shares from long-term liabilities to
shareholders' equity; and (v) the calculation and recognition of income taxes
based on enacted versus substantially enacted income tax rates.
The above-noted items do not represent a complete list of differences between US
GAAP and Canadian GAAP. Other less significant differences have also been
identified and accounted for. A detailed description of the differences and a
detailed reconciliation between the Corporation's annual audited consolidated
Canadian GAAP and annual audited consolidated US GAAP financial statements for
2011 is disclosed in Note 38 to the Corporation's voluntarily filed annual
audited consolidated US GAAP financial statements with accompanying notes
thereto for the year ended December 31, 2011, with 2010 comparatives. A detailed
reconciliation between the Corporation's interim unaudited consolidated 2011
Canadian GAAP and interim unaudited consolidated 2011 US GAAP financial
statements is provided in the above-noted voluntarily filed document under the
section "Supplemental Interim Consolidated Financial Statements for the Year
Ended December 31, 2011 (Unaudited)".
The audited quantification and reconciliation of the Corporation's consolidated
balance sheet as at December 31, 2011, prepared in accordance with US GAAP
versus Canadian GAAP, may be summarized as follows.
-- Total assets as at December 31, 2011 increased by approximately $603
million. The increase was due primarily to increases in regulatory
assets and utility capital assets in accordance with US GAAP.
-- Total liabilities as at December 31, 2011 increased by approximately
$337 million. The increase was due primarily to increases in long-term
debt, capital lease obligations and pension liabilities in accordance
with US GAAP, partially offset by the reclassification of preference
shares from liabilities to shareholders' equity.
-- Shareholders' equity as at December 31, 2011 increased by approximately
$266 million. The increase was due primarily to the reclassification of
preference shares from liabilities to shareholders' equity in accordance
with US GAAP, partially offset by a reduction in retained earnings of
approximately $37 million and an increase in accumulated other
comprehensive loss of approximately $21 million. Approximately half of
the reduction in retained earnings resulted from higher income taxes and
is expected to reverse in a future period once pending Canadian federal
income tax legislation is passed and proposed Part VI.1 tax rate changes
are enacted.
There were no material adjustments to the Corporation's consolidated 2011
earnings under US GAAP due to the Corporation's continued ability to apply
rate-regulated accounting policies.
The unaudited quantification and reconciliation of the Corporation's
consolidated statement of earnings for the three months ended March 31, 2011,
prepared in accordance with US GAAP versus Canadian GAAP, may be summarized as
follows:
-- Three Months Ended March 31, 2011 (Unaudited): Consolidated net earnings
recognized in accordance with US GAAP increased by $3 million, from $125
million to $128 million. The increase was due primarily to the
reclassification of preference share dividends totaling $4 million, in
accordance with US GAAP, from finance charges to earnings attributable
to preference equity shareholders, partially offset by a reduction in
earnings attributable to common equity shareholders of approximately of
$1 million.
Changes in Accounting Policies: Effective January 1, 2012, the FortisBC Energy
companies prospectively adopted the policy of accruing for non-ARO removal costs
in depreciation expense, as requested in their 2012-2013 RRAs and subsequently
approved by the BCUC in its April 2012 rate decision. The accrual of estimated
non-ARO removal costs is included in depreciation expense and the provision
balance is recognized as a long-term regulatory liability. Actual non-ARO
removal costs, net of salvage proceeds, are recorded against the regulatory
liability when incurred. Non-ARO removal costs are direct costs incurred by the
FortisBC Energy companies in taking assets out of service, whether through
actual removal of the assets or through disconnection of the assets from the
transmission or distribution system. Prior to 2012 non-ARO removal costs, net of
salvage proceeds, were recognized in operating expenses as incurred with
variances between actual non-ARO removal costs and those forecast for
rate-setting purposes recorded in a regulatory deferral account for future
recovery from, or refund to, customers in rates commencing in 2012. During the
first quarter of 2012, $4 million of non-ARO removal costs were accrued as a
part of depreciation expense. During the first quarter of 2011, $3 million of
non-ARO removal costs were recognized in operating expenses.
Prior to 2012 variances from forecast, adjusted for certain revenue and cost
variances which flowed through to customers, for rate-setting purposes were
shared equally between customers and FortisBC Electric. Prospectively from
January 1, 2012, the above sharing of positive or negative variances is no
longer in effect pursuant to the utility's filed 2012-2013 RRA, which is subject
to BCUC approval and reflects a COS rate-setting methodology. Beginning in 2012
variances from forecast for rate-setting purposes related to electricity
revenue, purchased power costs and certain other costs, are subject to full
deferral account treatment, to be recovered from, or refunded to, customers in
future rates and, therefore, are not subject to the sharing mechanism that
existed prior to 2012 and do not impact earnings in 2012.
New US GAAP Accounting Pronouncements: The following new US GAAP accounting
pronouncements that are applicable to, and were adopted by, Fortis effective
January 1, 2012 are described as follows:
Presentation of Comprehensive Income
The Corporation adopted the amendments to Accounting Standards Codification
("ASC") Topic 220, Comprehensive Income. The amended standard requires entities
to report components of comprehensive income in either a continuous statement of
comprehensive income or two separate but consecutive statements. Fortis
continues to report the components of comprehensive income in a separate but
consecutive statement.
Testing Goodwill for Impairment
The Corporation has prospectively adopted the amendments to ASC Topic 350,
Goodwill. The amended standard allows entities testing goodwill for impairment
to have the option of performing a qualitative assessment before calculating the
fair value of the reporting unit. If the qualitative factors indicate that the
fair value of the reporting unit is more likely than not (greater than a 50%
chance) to be greater than the carrying value, then the two-step impairment
test, including the quantification of the fair value of the reporting unit,
would not be required. In adopting the amendments, Fortis will perform a
qualitative assessment before calculating the fair value of its reporting units
when it performs its annual impairment test on October 1.
Fair Value Measurement
The Corporation adopted the amendments to ASC Topic 820, Fair Value Measurements
and Disclosures. The amended standard improves comparability of fair value
measurements presented and disclosed in financial statements prepared in
accordance with US GAAP. The amendment does not change what items are measured
at fair value but instead makes various changes to the guidance pertaining to
how fair value is measured. The above-noted changes did not materially impact
the Corporation's consolidated financial statements for the three months ended
March 31, 2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial
statements in accordance with US GAAP requires management to make estimates and
judgments that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenue and expenses during the
reporting periods. Estimates and judgments are based on historical experience,
current conditions and various other assumptions believed to be reasonable under
the circumstances. Additionally, certain estimates and judgments are necessary
since the regulatory environments in which the Corporation's utilities operate
often require amounts to be recorded at estimated values until these amounts are
finalized pursuant to regulatory decisions or other regulatory proceedings. Due
to changes in facts and circumstances and the inherent uncertainty involved in
making estimates, actual results may differ significantly from current
estimates. Estimates and judgments are reviewed periodically and, as adjustments
become necessary, are reported in earnings in the period they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the first quarter of 2012
from those disclosed in the 2011 Annual MD&A.
Contingencies: The Corporation and its subsidiaries are subject to various legal
proceedings and claims associated with ordinary course business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
Following the announcement of the proposed acquisition of CH Energy Group on
February 21, 2012, several complaints, which named Fortis and other defendants,
were filed in, or transferred to, the Supreme Court of the State of New York,
County of New York, challenging the proposed acquisition. The complaints
generally allege that the directors of CH Energy Group breached their fiduciary
duties in connection with the proposed transaction and that CH Energy Group,
Fortis, FortisUS Inc., and Cascade Acquisition Sub Inc. aided and abetted that
breach.
The outcome of these lawsuits is uncertain and cannot be predicted with any
certainty and, accordingly, no amount has been accrued in the consolidated
financial statements. An adverse judgment for monetary damages could have a
material adverse effect on the operations of the surviving company after the
completion of the acquisition. A preliminary injunction could delay or
jeopardize the completion of the acquisition and an adverse judgment granting
permanent injunctive relief could indefinitely enjoin completion of the
transaction. Subject to the foregoing, in management's opinion, based upon
currently known facts and circumstances, the outcome of such lawsuits is not
expected to have a material adverse effect on the consolidated financial
condition of Fortis. The defendants intend to vigorously defend themselves
against the lawsuits.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from Canada Revenue Agency for additional taxes related to the
taxation years 1999 through 2003. The exposure has been fully provided for in
the consolidated financial statements. FHI has begun the appeal process
associated with the assessments.
In 2009 FHI was named, along with other defendants, in an action related to
damages to property and chattels, including contamination to sewer lines and
costs associated with remediation, related to the rupture in July 2007 of an oil
pipeline owned and operated by Kinder Morgan, Inc. FHI has filed a statement of
defence. During the second quarter of 2010, FHI was added as a third party in
all of the related actions and all claims are expected to be tried at the same
time. The amount and outcome of the actions are indeterminable at this time and,
accordingly, no amount has been accrued in the 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 and has filed and
served a writ and statement of claim against FortisBC Electric, dated August 2,
2005. The Government of British Columbia has now disclosed that its claim
includes approximately $13.5 million in damages but that it has not fully
quantified its damages. In addition, private landowners have filed separate
writs and statements of claim dated August 19, 2005 and August 22, 2005 for
undisclosed amounts in relation to the same matter. FortisBC Electric and its
insurers are defending the claims. The outcome cannot be reasonably determined
and estimated at this time and, accordingly, no amount has been accrued in the
consolidated financial statements. A date for mediation of this matter has been
set for December 2012.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended June 30, 2010 through March 31, 2012. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements, which have been prepared in accordance with
US GAAP. The timing of the recognition of certain assets, liabilities, revenue
and expenses, as a result of regulation, may differ from that otherwise expected
using US GAAP for non-regulated entities. The nature of regulation is further
disclosed in Notes 2, 3 and 7 to the Corporation's 2011 annual audited
consolidated financial statements prepared in accordance with US GAAP. The
quarterly financial results are not necessarily indicative of results for any
future period and should not be relied upon to predict future performance.
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Summary of Quarterly Results Net Earnings
Attributable
(Unaudited) to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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March 31, 2012 1,149 121 0.64 0.62
December 31, 2011 1,034 82 0.44 0.43
September 30, 2011 699 56 0.30 0.30
June 30, 2011 846 57 0.32 0.32
March 31, 2011 1,159 116 0.66 0.64
December 31, 2010 1,032 127 0.73 0.71
September 30, 2010 717 43 0.25 0.25
June 30, 2010 831 53 0.31 0.31
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A summary of the past eight quarters reflects the Corporation's continued
organic growth, as well as the seasonality associated with its businesses.
Interim results will fluctuate due to the seasonal nature of gas and electricity
demand and water flows, as well as the timing and recognition of regulatory
decisions. Revenue is also affected by the cost of fuel and purchased power and
the commodity cost of natural gas, which are flowed through to customers without
markup. Given the diversified nature of the Fortis subsidiaries, seasonality may
vary. Most of the annual earnings of the FortisBC Energy companies are realized
in the first and fourth quarters. Earnings for the third quarter ended September
30, 2011 included the $11 million after-tax termination fee paid to Fortis by
Central Vermont Public Service Corporation ("CVPS"). Financial results from the
fourth quarter ended December 31, 2011 reflected the acquisition of the Hilton
Suites Winnipeg Airport hotel, which was acquired in October 2011. Financial
results from June 20, 2011 reflected the discontinuance of the consolidation
method of accounting for Belize Electricity due to the expropriation of the
utility by the GOB. For further information, refer to the "Key Trends and Risks
- Expropriated Assets" and "Business Risk Management - Investment in Belize"
sections of the 2011 Annual MD&A. Revenue for the third quarter ended September
30, 2010 reflected the favourable cumulative retroactive impact associated with
the 2010 revenue requirements decision at FortisAlberta.
March 2012/March 2011: Net earnings attributable to common equity shareholders
were $121 million, or $0.64 per common share, for the first quarter of 2012
compared to earnings of $116 million, or $0.66 per common share, for the first
quarter of 2011. A discussion of the quarter over quarter variance in financial
results is provided in the "Financial Highlights" section of this MD&A.
December 2011/December 2010: Net earnings attributable to common equity
shareholders were $82 million, or $0.44 per common share, for the fourth quarter
of 2011 compared to earnings of $127 million, or $0.73 per common share, for the
fourth quarter of 2010. Excluding the one-time $46 million favourable impact to
Newfoundland Power's earnings in the fourth quarter of 2010 due to the
rerecognition of a regulatory asset, as required under US GAAP, to recognize
amounts recoverable from customers upon regulatory approval of the adoption the
accrual method of accounting for OPEB costs, earnings increased $1 million
quarter over quarter. The increase in earnings was led by the FortisBC Energy
Companies, driven by rate base growth, lower-than-expected corporate income
taxes and finance charges in 2011, and higher gas transportation volumes to the
forestry and mining sectors, partially offset by both lower customer additions
and capitalized AFUDC. The above increase in earnings was partially offset by a
decrease in earnings at Newfoundland Power, Other Canadian Regulated Electric
Utilities, Fortis Turks and Caicos and Fortis Properties. The decrease in
earnings at Newfoundland Power reflected a lower allowed ROE and higher
operating expenses, partially offset by reduced energy supply costs in the
fourth quarter of 2011. Lower earnings at Other Canadian Regulated Electric
Utilities were due to decreased electricity sales and higher operating expenses.
Lower earnings at Fortis Turks and Caicos were due to higher depreciation and
operating expenses, partially offset by reduced energy supply costs in 2011
reflecting the use of new, more fuel-efficient generating units. Earnings at
Fortis Properties during the fourth quarter of 2010 reflected lower corporate
income tax rates, which reduced deferred taxes in that period. An 8% increase in
the weighted average number of common shares outstanding quarter over quarter,
largely associated with the public common equity offering in mid-2011, had the
impact of tempering earnings per common share.
September 2011/September 2010: Net earnings attributable to common equity
shareholders were $56 million, or $0.30 per common share, for the third quarter
of 2011 compared to earnings of $43 million, or $0.25 per common share, for the
third quarter of 2010. The increase in earnings was mainly due to the $11
million after-tax fee paid to Fortis in July 2011, following the termination of
the Merger Agreement between Fortis and CVPS. Results also improved due to rate
base growth associated with energy infrastructure investment, mainly at the
regulated utilities in western Canada, a net foreign exchange gain of
approximately $2.5 million after tax associated with the previously hedged
investment in Belize Electricity, lower-than-expected operating costs at the
FortisBC Energy companies due to the timing of spending and capitalization of
certain operating expenses in 2011 and a higher allowed ROE at Algoma Power. The
above increases in earnings were partially offset by the impact of the
regulator-approved reversal in the third quarter of 2010 of $4 million after tax
of project overrun costs previously expensed in 2009 related to the conversion
of Whistler customer appliances from propane to natural gas, the expropriation
of Belize Electricity and the resulting discontinuance of the consolidation
method of accounting for the utility since June 2011, lower capitalized AFUDC at
FortisBC Electric, lower non-regulated hydroelectric production in Belize and
the timing of recording the 2010 revenue requirements decision at FortisAlberta.
The favourable cumulative impact of the decision was recorded in the third
quarter of 2010 when the decision was received. A 4% increase in the weighted
average number of common shares outstanding quarter over quarter, largely
associated with the public common equity offering in mid-2011, had the impact of
tempering earnings per common share.
June 2011/June 2010: Net earnings attributable to common equity shareholders
were $57 million, or $0.32 per common share, for the second quarter of 2011
compared to earnings of $53 million, or $0.31 per common share, for the second
quarter of 2010. The increase was mainly due to improved performance at Canadian
Regulated Electric Utilities, driven by rate base growth associated with energy
infrastructure investment, mainly at the electric utilities in western Canada;
return earned on additional investment in automated meters at FortisAlberta, as
approved by the regulator; lower market-priced purchased power costs at FortisBC
Electric and a higher allowed ROE at Algoma Power. Results also improved due to
lower corporate business development costs. The above increases in earnings were
partially offset by the unfavourable impact of the timing of spending of certain
regulator-approved increased operating expenses at the FortisBC Energy companies
during 2011, lower non-regulated hydroelectric generation in Belize, and lower
contribution from Fortis Properties reflecting lower occupancies at hotel
operations in western Canada and increased operating expenses. During the second
quarter of 2011, the Government of Belize expropriated the Corporation's
investment in Belize Electricity.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
In an effort to optimize customer service operations within the FortisBC Energy
companies, a Customer Care Enhancement Project was implemented in January 2012
with new in-house customer contact and billing centres replacing the services of
an external third-party service provider. This represents a material change in
the Corporation's internal controls over financial reporting surrounding the
revenue, receivable and receipts cycle. Throughout the related systems design
and implementation, management had considered the control risks associated with
the systems changes and had performed procedures to obtain reasonable assurance
on the design of all new and significantly modified internal controls over
financial reporting as a result of the project. It has been concluded that
during the first quarter 2012, other than the above-noted change, there was no
change in the Corporation's internal controls over financial reporting that has
materially, or is reasonably likely to materially affect, the Corporation's
internal controls over financial reporting.
OUTLOOK
The Corporation's significant capital expenditure program, which is expected to
be approximately $5.5 billion over the five-year period 2012 through 2016,
should support continuing growth in earnings and dividends.
The pending acquisition of CH Energy Group is expected to close by the end of
the first quarter of 2013. Fortis remains disciplined and patient in its pursuit
of additional electric and gas utility acquisitions in the United States and
Canada that will add value for Fortis shareholders. Fortis will also pursue
growth in its non-regulated businesses in support of its regulated utility
growth strategy.
OUTSTANDING SHARE DATA
As at May 1, 2012, the Corporation had issued and outstanding approximately
189.3 million common shares; 5.0 million First Preference Shares, Series C; 8.0
million First Preference Shares, Series E; 5.0 million First Preference Shares,
Series F; 9.2 million First Preference Shares, Series G; and 10.0 million First
Preference Shares, Series H. Only the common shares of the Corporation have
voting rights.
The number of common shares of Fortis that would be issued if all outstanding
stock options and First Preference Shares, Series C and E were converted as at
May 1, 2012 is as follows.
----------------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at May 1, 2012 Number of
Common Shares
Security (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options 4.6
First Preference Shares, Series C 3.8
First Preference Shares, Series E 6.2
----------------------------------------------------------------------------
Total 14.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Additional information, including the Fortis 2011 Annual Information Form,
Management Information Circular and Annual Report, is available on SEDAR at
www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three months ended March 31, 2012 and 2011
(Unaudited)
Prepared in accordance with accounting principles generally accepted in the
United States
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31, December 31,
2012 2011
--------------------------------------------------------------------------
--------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 110 $ 87
Accounts receivable 696 638
Prepaid expenses 17 19
Inventories 76 134
Regulatory assets (Note 3) 168 219
Deferred income taxes 33 24
----------------------------------
1,100 1,121
Other assets 194 184
Regulatory assets (Note 3) 1,451 1,400
Deferred income taxes 3 8
Utility capital assets 9,064 8,968
Income producing properties 595 594
Intangible assets 324 325
Goodwill 1,563 1,565
----------------------------------
$ 14,294 $ 14,165
--------------------------------------------------------------------------
--------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 16) $ 76 $ 159
Accounts payable and other current
liabilities 1,009 990
Regulatory liabilities (Note 3) 76 43
Current installments of long-term debt 121 107
Current installments of capital lease
obligations 3 3
Deferred income taxes 3 5
----------------------------------
1,288 1,307
Other liabilities 574 573
Regulatory liabilities (Note 3) 592 555
Deferred income taxes 685 673
Long-term debt 5,780 5,805
Capital lease obligations 316 309
----------------------------------
9,235 9,222
----------------------------------
Shareholders' equity
Common shares (a)(Note 4) 3,050 3,036
Preference shares 912 912
Additional paid-in capital 15 14
Accumulated other comprehensive loss (96) (95)
Retained earnings 932 868
----------------------------------
4,813 4,735
Non-controlling interests (Note 5) 246 208
----------------------------------
5,059 4,943
----------------------------------
$ 14,294 $ 14,165
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(a) no par value: unlimited authorized shares; 189.3 million and 188.8
million issued and outstanding as at March 31, 2012 and December 31,
2011, respectively
Commitments and Contingent Liabilities (Notes 17 and 19)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended
2012 2011
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Revenue $ 1,149 $ 1,159
---------------------------------
Expenses
Energy supply costs 566 603
Operating 214 210
Depreciation and amortization 119 103
---------------------------------
899 916
---------------------------------
Operating income 250 243
Other income (expenses), net (Note 8) (3) 8
Finance charges (Note 9) 91 92
---------------------------------
Earnings before income taxes 156 159
Income taxes (Note 10) 23 31
---------------------------------
Net earnings $ 133 $ 128
---------------------------------
---------------------------------
Net earnings attributable to:
Non-controlling interests $ 1 $ 1
Preference equity shareholders 11 11
Common equity shareholders 121 116
---------------------------------
$ 133 $ 128
---------------------------------
---------------------------------
Earnings per common share (Note 11)
Basic $ 0.64 $ 0.66
Diluted $ 0.62 $ 0.64
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2012 2011
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Net earnings $ 133 $ 128
--------------------------------
--------------------------------
Other comprehensive (loss) income
Unrealized foreign currency translation
losses, net of hedging activities and tax (2) (3)
Unrealized employee future benefits gains,
net of tax 1 -
--------------------------------
(1) (3)
--------------------------------
Comprehensive income $ 132 $ 125
--------------------------------
--------------------------------
Comprehensive income attributable to:
Non-controlling interests $ 1 $ 1
Preference equity shareholders 11 11
Common equity shareholders 120 113
--------------------------------
$ 132 $ 125
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2012 2011
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating activities
Net earnings $ 133 $ 128
Items not affecting cash:
Depreciation - utility capital assets
and income producing properties 107 95
Amortization - intangible assets 11 9
Amortization - other 1 (1)
Deferred income taxes 5 (2)
Accrued employee future benefits 4 4
Equity component of allowance for
funds used during construction (2) (5)
Other (14) (1)
Change in long-term regulatory assets
and liabilities 4 18
Change in non-cash operating working
capital (Note 13) 79 57
-----------------------------------
328 302
-----------------------------------
Investing activities
Change in other assets and other
liabilities 4 (2)
Capital expenditures - utility capital
assets (211) (218)
Capital expenditures - income producing
properties (5) (3)
Capital expenditures - intangible assets (13) (11)
Contributions in aid of construction 14 12
Proceeds on sale of utility capital
assets and income producing properties - 5
-----------------------------------
(211) (217)
-----------------------------------
Financing activities
Change in short-term borrowings (83) (98)
Repayments of long-term debt and capital
lease obligations (4) (5)
Net borrowings under committed credit
facilities 7 15
Advances from non-controlling interests 41 17
Issue of common shares, net of costs and
dividends reinvested 2 11
Dividends
Common shares, net of dividends
reinvested (44) (35)
Preference shares (11) (11)
Subsidiary dividends paid to non-
controlling interests (2) (2)
-----------------------------------
(94) (108)
-----------------------------------
Change in cash and cash equivalents 23 (23)
Cash and cash equivalents, beginning of
period 87 107
-----------------------------------
Cash and cash equivalents, end of period $ 110 $ 84
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
13)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Accumulated
Additional Other
Common Preference Paid-in Comprehensive
Shares Shares Capital Loss
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 4)
As at December
31, 2011 $ 3,036 $ 912 $ 14 $ (95)
Net earnings - - - -
Other
comprehensive
loss - - - (1)
Common share
issues 14 - - -
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
($0.30 per
share) - - - -
Dividends
declared on
preference
shares - - - -
------------------------------------------------------------
As at March 31,
2012 $ 3,050 $ 912 $ 15 $ (96)
----------------------------------------------------------------------------
As at December
31, 2010 $ 2,575 $ 912 $ 12 $ (108)
Net earnings - - - -
Other
comprehensive
loss - - - (3)
Common share
issues 28 - (1) -
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
($0.29 per
share) - - - -
Dividends
declared on
preference
shares - - - -
------------------------------------------------------------
As at March 31,
2011 $ 2,603 $ 912 $ 12 $ (111)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Non-
Retained Controlling Total
Earnings Interests Equity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December
31, 2011 $ 868 $ 208 $ 4,943
Net earnings 132 1 133
Other
comprehensive
loss - - (1)
Common share
issues - - 14
Stock-based
compensation - - 1
Advances from
non-controlling
interests - 41 41
Foreign currency
translation
impacts - (2) (2)
Subsidiary
dividends paid
to non-
controlling
interests - (2) (2)
Dividends
declared on
common shares
($0.30 per
share) (57) - (57)
Dividends
declared on
preference
shares (11) - (11)
------------------------------------------------------------
As at March 31,
2012 $ 932 $ 246 $ 5,059
----------------------------------------------------------------------------
As at December
31, 2010 $ 774 $ 162 $ 4,327
Net earnings 127 1 128
Other
comprehensive
loss - - (3)
Common share
issues - - 27
Stock-based
compensation - - 1
Advances from
non-controlling
interests - 17 17
Foreign currency
translation
impacts - (3) (3)
Subsidiary
dividends paid
to non-
controlling
interests - (2) (2)
Dividends
declared on
common shares
($0.29 per
share) (51) - (51)
Dividends
declared on
preference
shares (11) - (11)
------------------------------------------------------------
As at March 31,
2011 $ 839 $ 175 $ 4,430
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2012 and 2011 (unless otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
Nature of Operations
Fortis Inc. ("Fortis" or the "Corporation") is principally an international
distribution utility holding company. Fortis segments its utility operations by
franchise area and, depending on regulatory requirements, by the nature of the
assets. Fortis also holds investments in non-regulated generation assets, and
commercial office and retail space and hotels, which are treated as two separate
segments. The Corporation's reporting segments allow senior management to
evaluate the operational performance and assess the overall contribution of each
segment to the long-term objectives of Fortis. Each reporting segment operates
as an autonomous unit, assumes profit and loss responsibility and is accountable
for its own resource allocation.
The following outlines each of the Corporation's reportable segments and is
consistent with the basis of segmentation as disclosed in the Corporation's 2011
annual audited consolidated financial statements prepared in accordance with
accounting principles generally accepted in the United States ("US GAAP").
REGULATED UTILITIES
The Corporation's interests in regulated gas and electric utilities in Canada
and the Caribbean by utility are as follows:
a. Regulated Gas Utilities - Canadian: Includes the FortisBC Energy
companies, which is comprised of FortisBC Energy Inc. ("FEI"), FortisBC
Energy (Vancouver Island) Inc. ("FEVI") and FortisBC Energy (Whistler)
Inc.
b. Regulated Electric Utilities - Canadian: Includes FortisAlberta;
FortisBC Electric; Newfoundland Power; and Other Canadian Electric
Utilities, which includes Maritime Electric and FortisOntario.
FortisOntario mainly includes Canadian Niagara Power Inc., Cornwall
Street Railway, Light and Power Company, Limited and Algoma Power Inc.
c. Regulated Electric Utilities - Caribbean: Includes Caribbean Utilities,
in which Fortis holds an approximate 60% controlling ownership interest;
wholly owned Fortis Turks and Caicos, which includes FortisTCI Limited
and Atlantic Equipment & Power (Turks and Caicos) Ltd.; and Belize
Electricity, in which Fortis held an approximate 70% controlling
ownership interest up to June 20, 2011. Effective June 20, 2011, the
Government of Belize ("GOB") expropriated the Corporation's investment
in Belize Electricity. As a result of no longer controlling the
operations of the utility, Fortis discontinued the consolidation method
of accounting for Belize Electricity, effective June 20, 2011.
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation
assets in Belize, Ontario, central Newfoundland, British Columbia and Upper New
York State.
NON-REGULATED - FORTIS PROPERTIES
Fortis Properties owns and operates 22 hotels, collectively representing 4,300
rooms in eight Canadian provinces, and approximately 2.7 million square feet of
commercial office and retail space primarily in Atlantic Canada.
CORPORATE AND OTHER
The Corporate and Other segment includes Fortis net corporate expenses, net
expenses of non-regulated FortisBC Holdings Inc. ("FHI") corporate-related
activities, and the financial results of FHI's 30% ownership interest in
CustomerWorks Limited Partnership "(CWLP") and of FHI's non-regulated wholly
owned subsidiary FortisBC Alternative Energy Services Inc. CWLP provides billing
and customer care services to utilities, municipalities and certain energy
companies. The contracts between CWLP and the FortisBC Energy companies ended on
December 31, 2011.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance
with US GAAP for interim financial statements. As a result, these interim
consolidated financial statements do not include all of the information and
disclosures required in the annual consolidated financial statements and should
be read in conjunction with the Corporation's 2011 annual audited consolidated
financial statements prepared in accordance with US GAAP and voluntarily filed
on the System for Electronic Document Analysis and Retrieval ("SEDAR") by Fortis
on March 16, 2012 (the "Corporation's 2011 US GAAP annual audited consolidated
financial statements"). In management's opinion, the interim consolidated
financial statements include all adjustments that are of a recurring nature and
necessary to present fairly the financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of gas and electricity
demand and water flows, as well as the timing and recognition of regulatory
decisions. Because of natural gas consumption patterns, most of the annual
earnings of the FortisBC Energy companies are realized in the first and fourth
quarters. Given the diversified group of companies, seasonality may vary.
The preparation of financial statements in accordance with US GAAP requires
management to make estimates and judgments that affect the reported amounts of
assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenue and
expenses during the reporting periods. Estimates and judgments are based on
historical experience, current conditions and various other assumptions believed
to be reasonable under the circumstances. Additionally, certain estimates and
judgments are necessary since the regulatory environments in which the
Corporation's utilities operate often require amounts to be recorded at
estimated values until these amounts are finalized pursuant to regulatory
decisions or other regulatory proceedings. 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 months ended March
31, 2012.
An evaluation of subsequent events through May 1, 2012, the date these interim
consolidated financial statements were approved by the Audit Committee of the
Board of Directors, was completed to determine whether circumstances warranted
recognition and disclosure of events or transactions in the interim consolidated
financial statements as at March 31, 2012.
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements have been prepared following the
same accounting policies and methods as those used in preparing the
Corporation's 2011 US GAAP annual audited consolidated financial statements,
except as described below.
Presentation of Comprehensive Income
Effective January 1, 2012, the Corporation adopted the amendments to Accounting
Standards Codification ("ASC") Topic 220, Comprehensive Income. The amended
standard requires entities to report components of comprehensive income in
either a continuous statement of comprehensive income or two separate but
consecutive statements. Fortis continues to report the components of
comprehensive income in a separate but consecutive statement.
Testing Goodwill for Impairment
Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic
350, Goodwill. The amended standard allows entities testing goodwill for
impairment to have the option of performing a qualitative assessment before
calculating the fair value of the reporting unit. If the qualitative factors
indicate that the fair value of the reporting unit is more likely than not
(greater than a 50% chance) to be greater than the carrying value, then the
two-step impairment test, including the quantification of the fair value of the
reporting unit, would not be required. In adopting the amendments, Fortis will
perform a qualitative assessment before calculating the fair value of its
reporting units when it performs its annual impairment test on October 1.
Fair Value Measurement
Effective January 1, 2012, the Corporation adopted the amendments to ASC Topic
820, Fair Value Measurements and Disclosures. The amended standard improves
comparability of fair value measurements presented and disclosed in financial
statements prepared in accordance with US GAAP. The amendment does not change
what items are measured at fair value but instead makes various changes to the
guidance pertaining to how fair value is measured. The above-noted changes did
not materially impact the Corporation's consolidated financial statements for
the three months ended March 31, 2012.
Changes in Accounting Policies
Effective January 1, 2012, the FortisBC Energy companies prospectively adopted
the policy of accruing for non-asset retirement obligation ("non-ARO") removal
costs in depreciation expense, as requested in their 2012-2013 Revenue
Requirements Applications and subsequently approved by the regulator in its
April 2012 rate decision. The accrual of estimated non-ARO removal costs is
included in depreciation expense and the provision balance is recognized as a
long-term regulatory liability. Actual non-ARO removal costs, net of salvage
proceeds, are recorded against the regulatory liability when incurred. Non-ARO
removal costs are direct costs incurred by the FortisBC Energy companies in
taking assets out of service, whether through actual removal of the assets or
through disconnection of the assets from the transmission or distribution
system. Prior to 2012 non-ARO removal costs, net of salvage proceeds, were
recognized in operating expenses as incurred with variances between actual
non-ARO removal costs and those forecast for rate-setting purposes recorded in a
regulatory deferral account for future recovery from, or refund to, customers in
rates commencing in 2012. During the first quarter of 2012, $4 million of
non-ARO removal costs were accrued as a part of depreciation expense. During the
first quarter of 2011, $3 million of non-ARO removal costs were recognized in
operating expenses.
Prior to 2012 variances from forecast, adjusted for certain revenue and cost
variances which flowed through to customers, for rate-setting purposes were
shared equally between customers and FortisBC Electric. Prospectively from
January 1, 2012, the above sharing of positive or negative variances is no
longer in effect pursuant to the utility's filed 2012-2013 Revenue Requirements
Application, which is subject to regulatory approval and reflects a cost of
service rate-setting methodology. Beginning in 2012 variances from forecast for
rate-setting purposes related to electricity revenue, purchased power costs and
certain other costs, are subject to full deferral account treatment, to be
recovered from, or refunded to, customers in future rates and, therefore, are
not subject to the sharing mechanism that existed prior to 2012 and do not
impact earnings in 2012.
3. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided
below. A detailed description of the nature of the Corporation's regulatory
assets and liabilities is provided in Note 7 to the Corporation's 2011 US GAAP
annual audited consolidated financial statements.
As at
March 31, December 31,
($ millions) 2012 2011
--------------------------------------------------------------------------
Regulatory assets
Deferred income taxes 645 630
Employee future benefits 425 428
Rate stabilization accounts - FortisBC Energy
companies 91 105
Deferred lease costs - FortisBC Electric 78 70
Rate stabilization accounts - electric utilities 55 55
Replacement energy deferral - Point Lepreau (1) 47 47
Deferred energy management costs 39 36
Deferred losses on disposal of utility capital
assets 28 23
Customer Care Enhancement Project cost deferral 25 13
Deferred operating overhead costs 24 22
Income taxes recoverable on other post-
employment benefit ("OPEB") plans 22 22
Whistler pipeline contribution deferral 16 16
Alberta Electric System Operator ("AESO")
charges deferral 11 44
Deferred development costs for capital 11 11
Pension cost variance deferral 11 10
Alternative energy projects cost deferral 9 8
Deferred costs - smart meters 8 8
Other regulatory assets 74 71
--------------------------------------------------------------------------
Total regulatory assets 1,619 1,619
Less: current portion (168) (219)
--------------------------------------------------------------------------
Long-term regulatory assets 1,451 1,400
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear
Generating Station
As at
March 31, December 31,
($ millions) 2012 2011
--------------------------------------------------------------------------
Regulatory liabilities
Non-ARO removal cost provision 359 354
Rate stabilization accounts - FortisBC Energy
companies 187 127
Rate stabilization accounts - electric utilities 38 33
Income tax variance deferral 10 12
Deferred interest 10 10
AESO charges deferral 9 12
Southern Crossing Pipeline deferral 7 8
Performance-based rate-setting incentive
liabilities 6 7
Unrecognized net gains on disposal of utility
capital assets 6 6
Other regulatory liabilities 36 29
--------------------------------------------------------------------------
Total regulatory liabilities 668 598
Less: current portion (76) (43)
--------------------------------------------------------------------------
Long-term regulatory liabilities 592 555
--------------------------------------------------------------------------
--------------------------------------------------------------------------
4. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended
March 31, 2012
Number of
Shares Amount
(in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning of period 188,828 3,036
Dividend Reinvestment Plan 400 13
Consumer Share Purchase Plan 13 -
Stock Option Plans 33 1
----------------------------------------------------------------------------
Balance, end of period 189,274 3,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. NON-CONTROLLING INTERESTS
Quarter Ended
March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Waneta Expansion Limited Partnership ("Waneta
Partnership") 157 128
Caribbean Utilities 70 73
Mount Hayes Limited Partnership (Note 17) 12 -
Preference shares of Newfoundland Power 7 7
--------------------------------------------------------------------------
246 208
--------------------------------------------------------------------------
--------------------------------------------------------------------------
6. STOCK-BASED COMPENSATION PLANS
In January 2012 21,417 Deferred Share Units ("DSUs") were granted to the
Corporation's Board of Directors, representing the equity component of the
Directors' annual compensation and, where opted, their annual retainers in lieu
of cash. Each DSU represents a unit with an underlying value equivalent to the
value of one common share of the Corporation.
In March 2012 44,863 Performance Share Units ("PSUs") were paid out to the
President and Chief Executive Officer ("CEO") of the Corporation at $32.14 per
PSU, for a total of approximately $1.4 million. The payout was made upon the
three-year maturation period in respect of the PSU grant made in March 2009 and
the President and CEO satisfying the payment requirements, as determined by the
Human Resources Committee of the Board of Directors of Fortis.
Stock-based compensation expense of $1.2 million was recognized for the three
months ended March 31, 2012 ($1.5 million for the three months ended March 31,
2011).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans and defined contribution pension plans, including
group registered retirement savings plans for employees. The Corporation and
certain subsidiaries also offer OPEB plans for qualifying employees. The net
benefit cost of providing the defined benefit pension and OPEB plans is detailed
in the following table.
Quarter Ended March 31
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2012 2011 2012 2011
--------------------------------------------------------------------------
Components of net
benefit cost:
Service costs 7 5 2 1
Interest costs 12 12 3 3
Expected return on plan
assets (12) (12) - -
Amortization of
actuarial losses 6 5 1 1
Amortization of past
service costs/plan
amendments - - (1) (1)
Regulatory adjustments (1) (2) 1 1
--------------------------------------------------------------------------
Net benefit cost 12 8 6 5
--------------------------------------------------------------------------
--------------------------------------------------------------------------
For the three months ended March 31, 2012, the Corporation expensed $4 million
($4 million for the three months ended March 31, 2011) related to defined
contribution pension plans.
8. OTHER INCOME (EXPENSES), NET
Quarter Ended
March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Equity component of allowance for funds used
during construction 2 5
Interest income 1 1
Net foreign exchange loss (2) -
Acquisition-related expenses (4) -
Other income, net of expenses - 2
--------------------------------------------------------------------------
(3) 8
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The net foreign exchange loss includes an approximate $1.5 million foreign
exchange loss on the translation into Canadian dollars of the Corporation's
long-term other asset associated with Belize Electricity (Note 18).
The acquisition-related expenses are associated with the proposed acquisition of
CH Energy Group, Inc. ("CH Energy Group"), as announced by the Corporation on
February 21, 2012.
9. FINANCE CHARGES
Quarter Ended
March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Interest - Long-term debt and capital lease
obligations 94 93
- Short-term borrowings and other 1 4
Debt component of allowance for funds used
during construction (4) (5)
--------------------------------------------------------------------------
91 92
--------------------------------------------------------------------------
--------------------------------------------------------------------------
10. INCOME TAXES
Income taxes differ from the amount that would be expected to be generated by
applying the enacted combined Canadian federal and provincial statutory income
tax rate to earnings before income taxes. The following is a reconciliation of
consolidated statutory taxes to consolidated effective taxes.
Quarter Ended
March 31
($ millions, except as noted) 2012 2011
--------------------------------------------------------------------------
Combined Canadian federal and provincial
statutory income tax rate 29.0% 30.5%
--------------------------------------------------------------------------
Statutory income tax rate applied to earnings
before income taxes 45 48
Difference between Canadian statutory rate and
rates applicable to foreign
subsidiaries (5) (5)
Difference in Canadian provincial statutory
rates applicable to subsidiaries
in different Canadian jurisdictions (1) (2)
Items capitalized for accounting purposes but
expensed for income tax
purposes (19) (16)
Difference between capital cost allowance and
amounts claimed for accounting
purposes 3 2
Non-deductible expenses 1 1
Difference between enacted and substantially
enacted income tax rates
associated with Part VI.1 tax - 1
Other (1) 2
--------------------------------------------------------------------------
Income taxes 23 31
--------------------------------------------------------------------------
Effective tax rate 14.7% 19.5%
--------------------------------------------------------------------------
--------------------------------------------------------------------------
As at March 31, 2012, the Corporation had approximately $96 million (December
31, 2011 - $86 million) in non-capital and capital loss carryforwards, of which
$13 million (December 31, 2011 - $13 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2014 and 2032.
11. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding. Diluted EPS was calculated using
the treasury stock method for options and the "if-converted" method for
convertible securities.
EPS were as follows:
Quarter Ended March 31
2012 2011
----------------------------------------------------------------
Earnings Weighted Earnings Weighted
to Common Average to Common Average
Shareholders Shares Shareholders Shares
($ millions)(in millions) EPS($ millions)(in millions) EPS
----------------------------------------------------------------------------
Basic EPS 121 189.0 $ 0.64 116 175.0 $ 0.66
Effect of
potential
dilutive
securities:
Stock
Options - 1.0 - 1.2
Preference
Shares 4 10.3 4 10.1
Convertible
Debentures - - 1 1.4
----------------------------------------------------------------------------
Diluted EPS 125 200.3 $ 0.62 121 187.7 $ 0.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
-----------------------------------------------------------------
Gas
Utilities Electric Utilities
-----------------------------------------------------------------
Quarter
Ended FortisBC
March 31, Energy
2012 Companies Newfound- Total
($ - Fortis FortisBC land Other Electric Electric
millions) Canadian Alberta Electric Power Canadian Canadian Caribbean
----------------------------------------------------------------------------
Revenue 548 108 87 192 91 478 63
Energy
supply
costs 302 - 25 142 58 225 40
Operating
expenses 70 39 21 20 12 92 8
Depreci-
ation and
amorti-
zation 40 35 12 11 7 65 7
----------------------------------------------------------------------------
Operating
income 136 34 29 19 14 96 8
Other
income
(expenses
), net - 2 - - - 2 -
Finance
charges 35 15 10 9 5 39 4
Income tax
expense
(recovery
) 19 - 3 3 2 8 -
----------------------------------------------------------------------------
Net
earnings
(loss) 82 21 16 7 7 51 4
Non-
contro-
lling
interests - - - - - - 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net
earnings
(loss)
attributa
ble to
common
equity
sharehold
ers 82 21 16 7 7 51 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 139
Identifiab
le assets 4,621 2,476 1,677 1,266 690 6,109 708
----------------------------------------------------------------------------
Total
assets 5,534 2,703 1,898 1,266 753 6,620 847
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expenditu
res (1) 46 79 17 15 9 120 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter
Ended
March 31,
2011
($
millions)
----------------------------------------------------------------------------
Revenue 574 100 83 183 91 457 75
Energy
supply
costs 344 - 23 134 60 217 46
Operating
expenses 74 35 18 20 12 85 11
Depreci-
ation and
amorti-
zation 27 33 11 10 6 60 9
----------------------------------------------------------------------------
Operating
income 129 32 31 19 13 95 9
Other
income
(expenses
), net 3 3 1 - - 4 1
Finance
charges 34 13 10 9 5 37 5
Income tax
expense
(recovery
) 23 1 3 4 2 10 -
----------------------------------------------------------------------------
Net
earnings
(loss) 75 21 19 6 6 52 5
Non-
contro-
lling
interests - - - - - - 1
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net
earnings
(loss)
attribu-
table to
common
equity
share-
holders 75 21 19 6 6 52 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 133
Identifi-
able
assets 4,397 2,188 1,613 1,244 658 5,703 775
----------------------------------------------------------------------------
Total
assets 5,310 2,415 1,834 1,244 721 6,214 908
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross
capital
expendi-
tures (1) 48 85 30 14 8 137 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------------
Quarter
Ended
March 31,
2012 Inter-
($ Fortis Fortis Corporate segment
millions) Generation Properties and Other eliminations Consolidated
-------------------------------------------------------------------------
Revenue 9 52 6 (7) 1,149
Energy
supply
costs - - - (1) 566
Operating
expenses 3 40 3 (2) 214
Depreci-
ation and
amorti-
zation 1 5 1 - 119
-------------------------------------------------------------------------
Operating
income 5 7 2 (4) 250
Other
income
(expenses
), net 1 - (5) (1) (3)
Finance
charges 1 6 11 (5) 91
Income tax
expense
(recovery
) - - (4) - 23
-------------------------------------------------------------------------
Net
earnings
(loss) 5 1 (10) - 133
Non-
contro-
lling
interests - - - - 1
Preference
share
dividends - - 11 - 11
-------------------------------------------------------------------------
Net
earnings
(loss)
attributa
ble to
common
equity
sharehold
ers 5 1 (21) - 121
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Goodwill - - - - 1,563
Identifiab
le assets 612 612 468 (399) 12,731
-------------------------------------------------------------------------
Total
assets 612 612 468 (399) 14,294
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gross
capital
expenditu
res (1) 48 5 - - 229
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Quarter
Ended
March 31,
2011
($
millions)
-------------------------------------------------------------------------
Revenue 7 50 6 (10) 1,159
Energy
supply
costs - - - (4) 603
Operating
expenses 3 37 2 (2) 210
Depreci-
ation and
amorti-
zation 1 5 1 - 103
-------------------------------------------------------------------------
Operating
income 3 8 3 (4) 243
Other
income
(expenses
), net 1 - - (1) 8
Finance
charges 1 6 14 (5) 92
Income tax
expense
(recovery
) - 1 (3) - 31
-------------------------------------------------------------------------
Net
earnings
(loss) 3 1 (8) - 128
Non-
contro-
lling
interests - - - - 1
Preference
share
dividends - - 11 - 11
-------------------------------------------------------------------------
Net
earnings
(loss)
attribu-
table to
common
equity
share-
holders 3 1 (19) - 116
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Goodwill - - - - 1,557
Identifi-
able
assets 422 576 473 (416) 11,930
-------------------------------------------------------------------------
Total
assets 422 576 473 (416) 13,487
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Gross
capital
expendi-
tures (1) 23 3 - - 232
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital
assets, including amounts for AESO transmission-related capital
projects, income producing properties and intangible assets, as
reflected on the consolidated statements of cash flows
Related party transactions are in the normal course of operations and are
measured at the exchange amount, which is the amount of consideration
established and agreed to by the related parties. The significant related party
inter-segment transactions primarily related to: (i) the sale of energy from
Fortis Generation to Belize Electricity, up to June 20, 2011; (ii) electricity
sales from Newfoundland Power to Fortis Properties; and (iii) finance charges on
related party borrowings. The significant related party inter-segment
transactions for the three months ended March 31, 2012 and 2011 were as follows:
Significant Inter-Segment Transactions Quarter Ended
March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Sales from Fortis Generation to Regulated Electric
Utilities - Caribbean - 4
Sales from Newfoundland Power to Fortis Properties 2 1
Inter-segment finance charges on lending from:
Corporate to Regulated Electric Utilities -
Caribbean 1 1
Corporate to Fortis Generation - 1
Corporate to Fortis Properties 4 3
--------------------------------------------------------------------------
--------------------------------------------------------------------------
The significant inter-segment asset balances were as follows:
As at March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Inter-segment lending from:
Fortis Generation to Other Canadian Electric
Utilities 20 20
Corporate to Regulated Electric Utilities -
Canadian - 50
Corporate to Regulated Electric Utilities -
Caribbean 76 58
Corporate to Fortis Generation 20 50
Corporate to Fortis Properties 257 222
Other inter-segment assets 26 16
--------------------------------------------------------------------------
Total inter-segment eliminations 399 416
--------------------------------------------------------------------------
--------------------------------------------------------------------------
13. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended
March 31
($ millions) 2012 2011
--------------------------------------------------------------------------
Cash paid for:
Interest 80 81
Income taxes 33 24
Change in non-cash operating working capital:
Accounts receivable (59) (36)
Prepaid expenses 2 (1)
Regulatory assets - current portion 43 (5)
Inventories 58 80
Accounts payable and other current liabilities 9 (7)
Regulatory liabilities - current portion 26 26
--------------------------------------------------------------------------
79 57
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Non-cash investing and financing activities:
Common share dividends reinvested 13 16
Additions to utility capital assets included in
accounts payable 7 41
Exercise of stock options into common shares - 1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
14. 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 March 31, 2012, the
Corporation's derivative contracts consisted of a foreign exchange forward
contract, natural gas swap and option contracts, and gas purchase contract
premiums, all held by the FortisBC Energy companies.
Volume of Derivative Activity
As at March 31, 2012, FEI and FEVI had the following notional volumes related to
an outstanding foreign exchange forward contract and natural gas derivatives,
designated for regulatory approval, that are expected to be settled as outlined
below.
2012 2013 2014
--------------------------------------------------------------------------
Foreign Exchange Forward Contract:
Cash exposure ($ millions) 1 - -
Weighted average CDN$ to US$ exchange rate 1.00 - -
Natural Gas Derivatives:
Swaps and options (petajoules) 26 18 7
Gas purchase contract premiums (petajoules) 70 20 9
--------------------------------------------------------------------------
Presentation of Derivative Instruments in the Consolidated Financial Statements
In the Corporation's consolidated balance sheets, derivative instruments are
presented on a net basis by counterparty, where the right of offset exists. The
net balances include outstanding cash collateral associated with derivative
positions.
The Corporation's outstanding derivative balances were as follows:
As at
March 31, December 31,
($ millions) 2012 2011
--------------------------------------------------------------------------
Gross derivatives balance (1) 132 136
Netting (2) - -
Cash collateral - -
--------------------------------------------------------------------------
Total derivative balances (3) 132 136
----------------------------
----------------------------
(1) Refer to Note 15 for a discussion of the valuation techniques used to
calculate the fair value of these derivative instruments.
(2) Positions, by counterparty, are netted where the intent and legal
right to offset exists.
(3) Unrealized losses of $132 million on commodity risk-related derivative
instruments were recognized as current regulatory assets as at March
31, 2012 (December 31, 2011 - $135 million), which would otherwise be
recognized on the consolidated statement of comprehensive income or as
accumulated other comprehensive loss. These amounts exclude the impact
of cash collateral postings.
Cash flows associated with the settlement of all derivative instruments are
included in operating cash flows on the Corporation's consolidated statements of
cash flows.
The majority of the FortisBC Energy companies' risk-related derivative
instruments contain collateral posting provisions tied to FEI's credit rating. A
downgrade of FEI below investment grade by any of the major credit rating
agencies could trigger margin calls and other cash requirements under FEI's gas
purchase, swap and option contracts. Most of the existing natural gas derivative
contracts are in liability positions and might be subject to margin calls and
other cash requirements if FEI was downgraded below investment grade.
15. 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 determine the fair value of all derivative
instruments.
The three levels of the fair value hierarchy are defined as follows:
Level 1: Fair value determined using unadjusted quoted prices in active
markets
Level 2: Fair value determined using pricing inputs that are observable
Level 3: Fair value determined using unobservable inputs only when relevant
observable inputs are not available
The fair values of the Corporation's financial instruments, including
derivatives, reflect a point-in-time estimate based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
The following table details the estimated fair value measurements of the
Corporation's financial instruments, all of which were measured using Level 2
inputs.
As at
Asset (Liability) March 31, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
--------------------------------------------------------------------------
Other asset - Belize
Electricity (1) 104 - (2) 106 - (2)
Long-term debt,
including current
portion (5,901) (7,207) (5,912) (7,296)
Waneta Partnership
promissory note (3) (45) (50) (45) (49)
Foreign exchange
forward contract (4) - - - -
Fuel option contracts
(4) - - (1) (1)
Natural gas
derivatives: (4)
Swaps and options (135) (135) (135) (135)
Gas purchase
contract premiums 3 3 - -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) Included in long-term other assets on the consolidated balance sheet
(2) The fair value of the Corporation's expropriated investment in Belize
Electricity determined under the GOB's valuation is significantly
lower than the fair value determined under the Corporation's
independent valuation of the utility. Due to uncertainty in the
ultimate amount and ability of the GOB to pay compensation owing to
Fortis for the expropriation of Belize Electricity, the Corporation
has recorded the long-term other asset at the carrying value of the
Corporation's previous investment in Belize Electricity, including
foreign exchange impacts.
(3) Included in long-term other liabilities on the consolidated balance
sheet
(4) The fair values of the derivatives were recorded in accounts payable
and other current liabilities as at March 31, 2012 and December 31,
2011.
The fair value of long-term debt is calculated using quoted market prices when
available. When quoted market prices are not available, the fair value is
determined by discounting the future cash flows of the specific debt instrument
at an estimated yield to maturity equivalent to benchmark government bonds or
treasury bills, with similar terms to maturity, plus a credit risk premium equal
to that of issuers of similar credit quality. Since the Corporation does not
intend to settle the long-term debt prior to maturity, the fair value estimate
does not represent an actual liability and, therefore, does not include exchange
or settlement costs.
The fair value of the foreign exchange forward contract was calculated using the
present value of cash flows based on a market foreign exchange rate and the
foreign exchange forward rate curve. Any change in the fair value of the foreign
exchange forward contract at FEI was deferred as a regulatory asset or liability
for recovery from, or refund to, customers in future rates, as permitted by the
regulator.
The fuel option contracts were 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 matured in March 2012.
The natural gas derivatives are used to fix the effective purchase price of
natural gas, as the majority of the natural gas supply contracts at the FortisBC
Energy companies have floating, rather than fixed, prices. Any resulting gains
or losses were recorded in regulatory assets or liabilities in the consolidated
balance sheet. The fair value of the natural gas derivatives was calculated
using the present value of cash flows based on market prices and forward curves
for the commodity cost of natural gas.
The fair values of the foreign exchange forward contract and the natural gas
derivatives were estimates of the amounts that the FortisBC Energy companies
would have had to receive or pay to terminate the outstanding contracts as at
the balance sheet date. As at March 31, 2012, none of the natural gas
derivatives were designated as hedges of the natural gas supply contracts.
However, any changes in the fair value of the natural gas derivatives were
deferred as a regulatory asset or liability for recovery from, or refund to,
customers in future rates, as permitted by the regulator.
16. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market
risk as a result of holding financial instruments in the normal course of
business.
Credit Risk Risk that a counterparty to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.
Liquidity Risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market Risk Risk that the fair value or future cash flows of a
financial instrument will fluctuate due to changes in
market prices. The Corporation is exposed to foreign
exchange risk, interest rate risk and commodity price
risk.
Credit Risk
For cash equivalents, trade and other accounts receivable, and other long-term
receivables, the Corporation's credit risk is limited to the carrying value on
the consolidated balance sheet. The Corporation generally has a large and
diversified customer base, which minimizes the concentration of credit risk. The
Corporation and its subsidiaries have various policies to minimize credit risk,
which include requiring customer deposits, prepayments and/or credit checks for
certain customers and performing disconnections and/or using third-party
collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution
service billings being to a relatively small group of retailers. As at March 31,
2012, the utility's gross credit risk exposure was approximately $156 million,
representing the projected value of retailer billings over a 60-day period. The
Company has reduced its exposure to approximately $9 million by obtaining from
the retailers either a cash deposit, bond, letter of credit or an
investment-grade credit rating from a major rating agency, or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The FortisBC Energy companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments. To help
mitigate credit risk, the FortisBC Energy companies deal with high
credit-quality institutions in accordance with established credit-approval
practices. The counterparties with which the FortisBC Energy companies have
significant transactions are A-rated entities or better. The Company uses
netting arrangements to reduce credit risk and net settles payments with
counterparties where net settlement provisions exist.
The following table summarizes the FortisBC Energy companies' net credit risk
exposure to its counterparties, as well as credit risk exposure to counter
parties accounting for greater than 10% net credit exposure.
As at
March 31, December 31,
($ millions, except for number of customers) 2012 2011
--------------------------------------------------------------------------
Gross credit exposure before credit collateral
(1) 136 136
Credit collateral - -
--------------------------------------------------------------------------
Net credit exposure (2) 136 136
--------------------------------------------------------------------------
Number of counterparties greater than 10% 4 4
Net exposure to counterparties greater than
10% 99 104
--------------------------------------------------------------------------
(1) Gross credit exposure equals mark-to-market value on physically and
financially settled contracts, notes receivable and net receivables
(payables) where netting is contractually allowed. Gross and net
credit exposure amounts reported do not include adjustments for time
value or liquidity.
(2) Net credit exposure is the gross credit exposure collateral minus
credit collateral (cash deposits and letters of credit).
The Corporation is exposed to credit risk associated with the amount and timing
of compensation that Fortis is entitled to receive from the GOB as a result of
the expropriation of the Corporation's investment in Belize Electricity by the
GOB on June 20, 2011. The Corporation has a long-term other asset of $104
million, including foreign exchange impacts, recognized on the consolidated
balance sheet related to its expropriated investment in Belize Electricity (Note
18).
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if
it, or one of its subsidiaries, fails to arrange sufficient and cost-effective
financing to fund, among other things, capital expenditures and the repayment of
maturing debt. The ability to arrange sufficient and cost-effective financing is
subject to numerous factors, including the consolidated results of operations
and financial position of the Corporation and its subsidiaries, conditions in
capital and bank credit markets, ratings assigned by rating agencies and general
economic conditions.
To help mitigate liquidity risk, the Corporation and its larger regulated
utilities have secured committed credit facilities to support short-term
financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed credit facility is available for interim financing
of acquisitions and for general corporate purposes. Depending on the timing of
cash payments from the subsidiaries, borrowings under the Corporation's
committed credit facility may be required from time to time to support the
servicing of debt and payment of dividends. As at March 31, 2012, average annual
consolidated long-term debt maturities and repayments over the next five years
are expected to be approximately $265 million. The combination of available
credit facilities and relatively low annual debt maturities and repayments
provide the Corporation and its subsidiaries with flexibility in the timing of
access to capital markets.
As at March 31, 2012, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.2 billion, of which $2.0 billion was
unused. The credit facilities are syndicated mostly with the seven largest
Canadian banks, with no one bank holding more than 20% of these facilities.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
December
Corporate Regulated Fortis March 31, 31,
($ millions) and Other Utilities Properties 2012 2011
--------------------------------------------------------------------------
Total credit
facilities 845 1,389 13 2,247 2,248
Credit
facilities
utilized:
Short-term
borrowings
(1) - (73) (3) (76) (159)
Long-term debt
(2) (31) (50) - (81) (74)
Letters of
credit
outstanding (1) (65) - (66) (66)
--------------------------------------------------------------------------
Credit
facilities
unused 813 1,201 10 2,024 1,949
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(1) The weighted average interest rate on short-term borrowings was
approximately 1.7% as at March 31, 2012 (December 31, 2011 - 1.2%).
(2) As at March 31, 2012, credit facility borrowings classified as long-
term included $16 million (December 31, 2011 - $16 million) that was
included in current installments of long-term debt on the consolidated
balance sheet. The weighted average interest rate on credit facility
borrowings classified as long-term debt was approximately 2.0% as at
March 31, 2012 (December 31, 2011 - 2.1%).
As at March 31, 2012 and December 31, 2011, certain borrowings under the
Corporation's and subsidiaries' credit facilities were classified as long-term
debt. These borrowings are under long-term committed credit facilities and
management's intention is to refinance these borrowings with long-term permanent
financing during future periods.
In March 2012 Newfoundland Power renegotiated and amended its $100 million
unsecured committed credit facility, obtaining an extension to the maturity of
the facility to August 2017 from August 2015. The amended credit facility
agreement reflects a decrease in pricing but, otherwise, contains substantially
similar terms and conditions as the previous credit facility agreement.
In April 2012 FortisBC Electric renegotiated and amended its credit facility
agreement resulting in an extension to the maturity of the Company's $150
million unsecured committed revolving credit facility with $100 million now
maturing in May 2015 and $50 million now maturing in May 2013.
Fortis has requested an increase in the amount available for borrowing under its
committed corporate credit facility from $800 million to $1 billion, as
permitted under the credit facility agreement, and expects the increase to be
available in May 2012.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
March 31, 2012, the Corporation's credit ratings are as follows:
Standard & Poor's A-/Credit Watch - Negative (unsecured debt credit
rating)
DBRS A(low)/Under Review - Developing Implications
(unsecured debt credit rating)
The above credit ratings reflect the Corporation's low business-risk profile and
diversity of its operations, the stand-alone nature and financial separation of
each of the regulated subsidiaries of Fortis, management's commitment to
maintaining low levels of debt at the holding company level, the Corporation's
reasonable credit metrics and its demonstrated ability and continued focus on
acquiring and integrating stable regulated utility businesses financed on a
conservative basis. In February 2012, after the announcement by Fortis that it
had entered into an agreement to acquire CH Energy Group, DBRS placed the
Corporation's credit rating under review with developing implications.
Similarly, S&P placed the Corporation's credit rating on credit watch with
negative implications.
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 exposure through the use of US
dollar borrowings at the corporate level. The foreign exchange gain or loss on
the translation of US dollar-denominated interest expense partially offsets the
foreign exchange loss or gain on the translation of the Corporation's foreign
subsidiaries' earnings, which are denominated in US dollars. The reporting
currency of Caribbean Utilities, Fortis Turks and Caicos, FortisUS Energy and
BECOL is the US dollar. Belize Electricity's financial results were denominated
in Belizean dollars, which are pegged to the US dollar.
As at March 31, 2012, the Corporation's corporately issued US$550 million
(December 31, 2011 - US$550 million) long-term debt had been designated as an
effective hedge of the Corporation's foreign net investments. As at March 31,
2012, the Corporation had approximately US$8 million (December 31, 2011 - US$6
million) in foreign net investments remaining to be hedged. Foreign currency
exchange rate fluctuations associated with the translation of the Corporation's
corporately issued US dollar borrowings that are designated as hedges are
recorded in other comprehensive income and serve to help offset unrealized
foreign currency exchange gains and losses on the net investments in foreign
subsidiaries, which are also recorded in other comprehensive income.
Effective June 20, 2011, the Corporation's asset associated with its previous
investment in Belize Electricity does not qualify for hedge accounting as Belize
Electricity is no longer a foreign subsidiary of Fortis. As a result, during
2011, a portion of corporately issued debt that previously hedged the former
investment in Belize Electricity was no longer an effective hedge. Effective
from June 20, 2011, foreign exchange gains and losses on the translation of the
asset associated with Belize Electricity and the corporately issued US
dollar-denominated debt that previously qualified as a hedge of the investment
were recognized in earnings. As a result, the Corporation recognized a foreign
exchange loss of approximately $1.5 million in earnings during the three months
ended March 31, 2012 (Note 8).
FEI's US dollar payments under a contract for the implementation of a customer
care information system are exposed to fluctuations in the US dollar-to-Canadian
dollar exchange rate. FEI entered into a foreign exchange forward contract to
hedge this exposure. FEI has regulatory approval to defer any increase or
decrease in the fair value of the foreign exchange forward contract for recovery
from, or refund to, customers in future rates.
Interest Rate Risk
The Corporation and its subsidiaries are exposed to interest rate risk
associated with short-term borrowings and floating-rate debt. The Corporation
and its subsidiaries may enter into interest rate swap agreements to help reduce
this risk.
Commodity Price Risk
The FortisBC Energy companies are exposed to commodity price risk associated
with changes in the market price of natural gas. This risk has been minimized by
entering into natural gas derivatives that effectively fix the price of natural
gas purchases. The natural gas derivatives are recorded on the consolidated
balance sheet at fair value and any change in the fair value is deferred as a
regulatory asset or liability, subject to regulatory approval, for recovery
from, or refund to, customers in future rates.
The price risk-management strategy of the FortisBC Energy companies aims to
improve the likelihood that natural gas prices remain competitive with
electricity rates, temper gas price volatility on customer rates and reduce the
risk of regional price discrepancies. In 2011 the BCUC determined that commodity
hedging in the current environment was not a cost-effective means to meet the
objectives of price competitiveness and rate stability. The BCUC concurrently
denied FEI's 2011-2014 Price Risk Management Plan ("PRMP") with the exception of
certain elements to address regional price discrepancies. As a result, the
FortisBC Energy companies have suspended all commodity hedging activities, with
the exception of certain limited swaps as permitted by the BCUC. The existing
hedging contracts will continue in effect through to their maturity and the
FortisBC Energy companies' ability to fully recover the commodity cost of gas in
customer rates remains unchanged. 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.
17. COMMITMENTS
There were no material changes in the nature and amount of the Corporation's
commitments from the commitments disclosed in the Corporation's 2011 US GAAP
annual audited consolidated financial statements, except as described below.
In January 2012 two First Nations bands each invested approximately $6 million
in equity in the Mount Hayes liquefied natural gas storage facility,
representing a 15% equity interest in the Mount Hayes Limited Partnership, with
FEVI holding the controlling 85% ownership interest (Note 5). The
non-controlling interests hold put options, which, if exercised, would require
FEVI to repurchase the 15% ownership interest for cash, in accordance with the
terms of the partnership agreement.
In April 2012 the December 31, 2011 actuarial valuation of the defined benefit
pension plan at Newfoundland Power was completed. As a result Newfoundland Power
is required to fund a solvency deficiency of approximately $53.5 million,
including interest, over five years beginning in 2012. The increase in funding
contributions is expected to be recovered from customers in future rates.
18. EXPROPRIATED ASSETS
Belize Electricity
On June 20, 2011, the GOB enacted legislation leading to the expropriation of
the Corporation's investment in Belize Electricity. As a result of no longer
controlling the operations of the utility, the Corporation has discontinued the
consolidation method of accounting for Belize Electricity, effective June 20,
2011, and has classified the book value of the previous investment in the
utility as a long-term other asset on the interim consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with
respect to the challenge of the legality of the expropriation of the
Corporation's investment in Belize Electricity and court proceedings are
continuing. Fortis commissioned an independent valuation of its expropriated
investment in Belize Electricity and submitted its claim for compensation to the
GOB in November 2011.
The GOB also commissioned a valuation of Belize Electricity and communicated the
results of such valuation in its response to the Corporation's claim for
compensation. The fair value of Belize Electricity determined under the GOB's
valuation is significantly lower than the fair value determined under the
Corporation's valuation. Pursuant to the expropriation action, Fortis is
assessing alternative options for obtaining fair compensation from the GOB.
Exploits Partnership
The Exploits Partnership is owned 51% by Fortis Properties and 49% by
AbitibiBowater Inc. ("Abitibi"). The Exploits Partnership operated two
non-regulated hydroelectric generating facilities in central Newfoundland with a
combined capacity of approximately 36 MW. In December 2008 the Government of
Newfoundland and Labrador expropriated Abitibi's hydroelectric assets and water
rights in Newfoundland, including those of the Exploits Partnership. The
newsprint mill in Grand Falls-Windsor closed on February 12, 2009, subsequent to
which the day-to-day operations of the Exploits Partnership's hydroelectric
generating facilities were assumed by Nalcor Energy as an agent for the
Government of Newfoundland and Labrador with respect to expropriation matters.
The Government of Newfoundland and Labrador has publicly stated that it is not
its intention to adversely affect the business interests of lenders or
independent partners of Abitibi in the province. The loss of control over cash
flows and operations required Fortis to cease consolidation of the Exploits
Partnership, effective February 12, 2009. Discussions between Fortis Properties
and Nalcor Energy with respect to expropriation matters are ongoing.
19. 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
Following the announcement of the proposed acquisition of CH Energy Group on
February 21, 2012, several complaints, which named Fortis and other defendants,
were filed in, or transferred to, the Supreme Court of the State of New York,
County of New York, challenging the proposed acquisition. The complaints
generally allege that the directors of CH Energy Group breached their fiduciary
duties in connection with the proposed transaction and that CH Energy Group,
Fortis, FortisUS Inc., and Cascade Acquisition Sub Inc. aided and abetted that
breach.
The outcome of these lawsuits is uncertain and cannot be predicted with any
certainty and, accordingly, no amount has been accrued in the consolidated
financial statements. An adverse judgment for monetary damages could have a
material adverse effect on the operations of the surviving company after the
completion of the acquisition. A preliminary injunction could delay or
jeopardize the completion of the acquisition and an adverse judgment granting
permanent injunctive relief could indefinitely enjoin completion of the
transaction. Subject to the foregoing, in management's opinion, based upon
currently known facts and circumstances, the outcome of such lawsuits is not
expected to have a material adverse effect on the consolidated financial
condition of Fortis. The defendants intend to vigorously defend themselves
against the lawsuits.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from Canada Revenue Agency for additional taxes related to the
taxation years 1999 through 2003. The exposure has been fully provided for in
the consolidated financial statements. FHI has begun the appeal process
associated with the assessments.
In 2009 FHI was named, along with other defendants, in an action related to
damages to property and chattels, including contamination to sewer lines and
costs associated with remediation, related to the rupture in July 2007 of an oil
pipeline owned and operated by Kinder Morgan, Inc. FHI has filed a statement of
defence. During the second quarter of 2010, FHI was added as a third party in
all of the related actions and all claims are expected to be tried at the same
time. The amount and outcome of the actions are indeterminable at this time and,
accordingly, no amount has been accrued in the 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 and has filed and
served a writ and statement of claim against FortisBC Electric dated August 2,
2005. The Government of British Columbia has now disclosed that its claim
includes approximately $13.5 million in damages but that it has not fully
quantified its damages. In addition, private landowners have filed separate
writs and statements of claim dated August 19, 2005 and August 22, 2005 for
undisclosed amounts in relation to the same matter. FortisBC Electric and its
insurers are defending the claims. The outcome cannot be reasonably determined
and estimated at this time and, accordingly, no amount has been accrued in the
consolidated financial statements. A date for mediation of this matter has been
set for December 2012.
CORPORATE INFORMATION
Fortis Inc. is the largest investor-owned distribution utility in Canada, with
total assets of more than $14 billion and fiscal 2011 revenue totalling
approximately $3.7 billion. The Corporation serves more than 2,000,000 gas and
electricity customers. Its regulated holdings include electric distribution
utilities in five Canadian provinces and two Caribbean countries and a natural
gas utility in British Columbia. Fortis owns and operates non-regulated
generation assets across Canada and in Belize and Upper New York State. It also
owns hotels and commercial office and retail space in Canada.
The Common Shares, First Preference Shares, Series C; First Preference Shares,
Series E; First Preference Shares, Series F; First Preference Shares, Series G;
and First Preference Shares, Series H of Fortis are traded on the Toronto Stock
Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G and
FTS.PR.H, respectively.
Share Transfer Agent and Registrar:
Computershare Trust Company of Canada
9th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.computershare.com/fortisinc
Additional information, including the Fortis 2011 Annual Information Form,
Management Information Circular and Annual Report, are available on SEDAR at
www.sedar.com and on the Corporation's web site at www.fortisinc.com.
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