Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved second quarter
net earnings attributable to common equity shareholders of $62 million, or $0.33
per common share, compared to $57 million, or $0.32 per common share, for the
second quarter of 2011. For the first half of 2012, net earnings attributable to
common equity shareholders were $183 million, or $0.97 per common share,
compared to $173 million, or $0.98 per common share, for the first half of last
year.
Performance for the quarter was driven by FortisAlberta and higher non-regulated
hydroelectric generation, partially offset by increased corporate costs. A 7%
increase in the weighted average number of common shares outstanding quarter
over quarter, largely associated with the issuance of common equity in mid-2011,
and $4 million ($3 million after tax), or $0.02 per common share, of
acquisition-related expenses incurred during the second quarter of 2012
associated with the CH Energy Group, Inc. ("CH Energy Group") transaction
lowered earnings per common share in the second quarter of 2012.
Canadian Regulated Electric Utilities contributed earnings of $52 million, up $9
million from the second quarter of 2011. Earnings at FortisAlberta increased $8
million quarter over quarter, mainly due to growth in energy infrastructure
investment, and increased transmission revenue and reduced depreciation as
approved by the regulator, partially offset by a lower allowed rate of return on
common shareholder's equity ("ROE").
FortisBC Electric and the City of Kelowna (the "City") are in preliminary
discussions for FortisBC Electric to purchase the City's electricity
distribution utility, which currently serves approximately 15,000 customers. The
City's electricity distribution assets have been operated and maintained by
FortisBC Electric since 2000. Closing of the transaction is subject to certain
conditions, negotiation of definitive agreements and certain approvals,
including municipal and regulatory approvals. The parties are working towards
closing the transaction by the end of the first quarter of 2013.
Canadian Regulated Gas Utilities delivered earnings of $13 million compared to
$15 million for the second quarter of 2011. The decrease in earnings was mainly
due to lower-than-expected customer additions and lower capitalized allowance
for funds used during construction during 2012, partially offset by
higher-than-expected gas transportation volumes to industrial customers.
Regulatory decisions were received in April 2012 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 during the third quarter of
2012. A Generic Cost of Capital Proceeding in British Columbia to determine cost
of capital, effective January 1, 2013, and a performance-based rate-regulation
initiative in Alberta are continuing.
In June 2012 Newfoundland Power received regulatory approval of an increase in
its allowed ROE to 8.80% for 2012 up from 8.38% for 2011. The Company expects to
file a general rate application for 2013 customer rates during the third quarter
of 2012.
Caribbean Regulated Electric Utilities contributed $6 million of earnings,
comparable to the second quarter of 2011.
Consolidated capital expenditures, before customer contributions, were
approximately $511 million in the first half of 2012. The Customer Care
Enhancement Project at FortisBC's gas business came into service at the
beginning of January 2012. Construction continues on time and on budget on the
$900 million Waneta Expansion hydroelectric generating facility (the "Waneta
Expansion") with approximately $345 million in total having been spent on the
Waneta Expansion since construction began in late 2010.
Non-Regulated Fortis Generation contributed $5 million to earnings, up $3
million quarter over quarter. Improved performance mainly related to increased
production in Belize due to higher rainfall.
Fortis Properties delivered earnings of $8 million, comparable to the second
quarter of 2011.
Corporate and other expenses were $22 million, $5 million higher quarter over
quarter, largely the result of CH Energy Group acquisition-related expenses of
approximately $4 million ($3 million after tax) incurred during the second
quarter of 2012 and a lower income tax recovery, partially offset by a foreign
exchange gain of approximately $2 million recognized during the second quarter
of 2012.
Cash flow from operating activities was $583 million for the first half of 2012,
up $50 million from the first half of 2011, driven by favourable changes in
working capital and higher earnings.
In February 2012 Fortis announced that it had entered into an agreement to
acquire CH Energy Group for an aggregate purchase price of approximately US$1.5
billion, including the assumption of approximately US$500 million of debt on
closing. CH Energy Group's main business, Central Hudson Gas & Electric
Corporation ("Central Hudson"), serves approximately 375,000 electric and gas
customers in New York State's Mid-Hudson River Valley. The transaction received
CH Energy Group shareholder approval in June 2012 and regulatory approval from
the Federal Energy Regulatory Commission and the Committee on Foreign Investment
in the United States in July 2012. The New York State Public Service Commission
is currently reviewing the application for approval of the transaction jointly
filed by Fortis and CH Energy Group in April 2012. The acquisition is expected
to close by the end of the first quarter of 2013 and be immediately accretive to
earnings per common share of Fortis, excluding acquisition-related expenses.
Fortis raised gross proceeds of approximately $601 million in June 2012 upon
issuance of 18,500,000 Subscription Receipts at $32.50 each to finance a portion
of the purchase price of CH Energy Group. The proceeds are being held by an
escrow agent pending satisfaction of closing conditions contained in the
purchase agreement with CH Energy Group. Each Subscription Receipt will entitle
the holder thereof to receive, on satisfaction of the closing conditions, one
common share of Fortis.
In May 2012 and July 2012, Standard & Poor's Ratings Service ("S&P") and DBRS,
respectively, affirmed the Corporation's debt credit ratings at A- and A(low),
respectively. Also, S&P removed the rating from credit watch with negative
implications and DBRS removed the rating from under review with developing
implications, where the ratings had been placed in February 2012 following the
announcement of the CH Energy Group acquisition.
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 second quarter of 2012 or 2011.
"The second half of 2012 will continue to be very busy for Fortis, with
significant regulatory proceedings continuing at our largest utilities and our
annual capital program projected to reach a record $1.3 billion," says Stan
Marshall, President and Chief Executive Officer, Fortis Inc. "This investment in
energy infrastructure will ensure we continue to meet our customers' energy
needs with safe, reliable and cost-efficient supply."
"We are also focused on closing the CH Energy Group transaction by the end of
the first quarter of 2013," says Marshall. "The addition of CH Energy Group to
Fortis will deliver tangible benefits to customers of Central Hudson and support
the utility's focus on enhancing customer service. Central Hudson's capital
program from 2013 through 2016 is expected to add approximately $0.5 billion to
the Fortis consolidated five-year $5.5 billion capital program," he explains.
"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 and six months ended June 30, 2012
Dated July 31, 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 and six months ended June
30, 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
possible acquisition of the City of Kelowna's electricity distribution utility
by FortisBC Electric; the expected timing of filing regulatory applications and
of receipt of regulatory decisions; and 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 acquisition-related expenses.
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 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 receipt of regulatory and other approvals required in connection with the
acquisition of CH Energy Group; 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 close the acquisition of CH
Energy Group, the timing of such closing and the realization of the anticipated
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 and six months ended June 30, 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 Upstate New York, and hotels and commercial office and retail space
in Canada. Year-to-date June 30, 2012, the Corporation's electricity
distribution systems met a combined peak demand of approximately 5,215 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 and six months ended June 30, 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").
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.: In February 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. 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 transaction
received CH Energy Group shareholder approval in June 2012 and regulatory
approval from the Federal Energy Regulatory Commission and the Committee on
Foreign Investment in the United States in July 2012.
The acquisition is also subject to certain other approvals, including approval
by the New York State Public Service Commission (the "NYSPSC"), and satisfaction
of customary closing conditions. The NYSPSC is currently reviewing the
application for approval of the transaction jointly filed by Fortis and CH
Energy Group in April 2012. The acquisition is expected to close by the end of
the first quarter of 2013 and be immediately accretive to earnings per common
share, excluding acquisition-related expenses.
Subscription Receipts: In June 2012, to finance a portion of the pending
acquisition of CH Energy Group, Fortis sold 18,500,000 Subscription Receipts at
$32.50 each through a bought-deal offering underwritten by a syndicate of
underwriters led by CIBC World Markets Inc., Scotia Capital Inc. and TD
Securities Inc. (collectively the "Underwriters"), resulting in gross proceeds
of approximately $601 million. The gross proceeds from the sale of the
Subscription Receipts are being held by an escrow agent, pending receipt of all
required approvals and satisfaction of closing conditions included in the
agreement to acquire CH Energy Group (the "Release Conditions"). The
Subscription Receipts began trading on the Toronto Stock Exchange on June 27,
2012 under the symbol "FTS.R".
Each Subscription Receipt will entitle the holder thereof to receive, on
satisfaction of the Release Conditions and without payment of additional
consideration, one common share of Fortis and a cash payment equal to the
dividends declared on Fortis common shares to holders of record during the
period from June 27, 2012 to the date of issuance of the common shares in
respect of the Subscription Receipts.
If the Release Conditions are not satisfied by June 30, 2013, or if the share
purchase agreement relating to the acquisition of CH Energy Group is terminated
prior to such time, holders of Subscription Receipts shall be entitled to
receive from the escrow agent an amount equal to the full subscription price
thereof plus their pro rata share of the interest earned on such amount.
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. 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 caused 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 "New Accounting Policies" section of this MD&A.
Purchase of the Electricity Distribution Assets in Port Colborne: In April 2012
FortisOntario exercised its option to purchase all of the assets previously
leased by the Company under an operating lease agreement with the City of Port
Colborne for the purchase option price of approximately $7 million. The exercise
of the purchase option, which qualifies as a business combination, provides
ownership and legal title to all of the assets, including equipment, real
property and distribution assets, which constitutes the electricity distribution
system in Port Colborne.
Pending Acquisition of the Electricity Distribution Utility from the City of
Kelowna: FortisBC Electric and the City of Kelowna (the "City") are in
preliminary discussions for FortisBC Electric to purchase the City's electricity
distribution utility, which currently serves approximately 15,000 customers.
FortisBC Electric provides the City with electricity under a wholesale tariff
and has operated and maintained its assets since 2000. Closing of the
transaction is subject to certain conditions, negotiation of definitive
agreements and certain approvals, including municipal and regulatory approvals.
The parties are working towards closing the transaction by the end of the first
quarter of 2013.
Re-Organization of Non-Regulated Generation Operations: Effective July 1, 2012,
the legal ownership of the six small non-regulated hydroelectric generating
facilities in eastern Ontario, with a combined generating capacity of 8 MW, was
transferred from Fortis Properties to a limited partnership directly held by
Fortis. FortisBC Electric is assuming management responsibility for the
operations of the above-noted facilities, as well as for the four non-regulated
hydroelectric generating facilities in Upstate New York, with a combined
generating capacity of 23 MW, owned by FortisUS Energy Corporation ("FortisUS
Energy").
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of profitable growth with earnings per common
share as the primary measure of performance. The Corporation's business is
segmented by franchise area and, depending on regulatory requirements, by the
nature of the assets. Key financial highlights for the second quarter and
year-to-date periods ended June 30, 2012 and June 30, 2011 are provided in the
following table.
----------------------------------------------------------------------------
Consolidated Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions, except for
common share data) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
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Revenue 792 846 (54) 1,941 2,005 (64)
Energy Supply Costs 291 358 (67) 857 961 (104)
Operating Expenses 204 209 (5) 418 419 (1)
Depreciation and
Amortization 114 102 12 233 205 28
Other Income (Expenses),
Net - 4 (4) (3) 12 (15)
Finance Charges 92 93 (1) 183 185 (2)
Income Taxes 14 16 (2) 37 47 (10)
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Net Earnings 77 72 5 210 200 10
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Net Earnings Attributable
to:
Non-Controlling
Interests 3 3 - 4 4 -
Preference Equity
Shareholders 12 12 - 23 23 -
Common Equity
Shareholders 62 57 5 183 173 10
----------------------------------------------------------------------------
Net Earnings 77 72 5 210 200 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic Earnings per Common
Share ($) 0.33 0.32 0.01 0.97 0.98 (0.01)
Diluted Earnings per
Common Share ($) 0.33 0.32 0.01 0.95 0.97 (0.02)
Weighted Average Number
of Common Shares
Outstanding (# millions) 189.6 177.1 12.5 189.3 175.8 13.5
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Cash Flow from Operating
Activities 255 231 24 583 533 50
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Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
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 industrial
customers
-- Lower electricity sales at Newfoundland Power for the quarter and at
FortisBC Electric, Caribbean Utilities and FortisOntario for the quarter
and year-to-date 2012
Favourable
-- An increase in gas delivery rates and the base component of electricity
rates at the regulated utilities in western Canada, consistent with
final or 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
-- Increased electricity sales at Newfoundland Power and Fortis Turks and
Caicos year to date and at Maritime Electric for the quarter and year-
to-date 2012
-- The flow through in customer electricity rates of overall higher energy
supply costs
-- 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
-- Approximately $3 million of net transmission revenue recognized at
FortisAlberta in the second quarter of 2012, of which approximately $1
million related to the first quarter of 2012, as a result of the 2012
distribution revenue requirements decision received in April 2012
-- Approximately $3 million for the quarter and $4 million year to date of
favourable foreign exchange associated with the translation of US
dollar-denominated revenue, due to the strengthening of the US dollar
relative to the Canadian dollar period over period
Factors Contributing to Quarterly and Year-to-Date
Energy Supply Costs Variances
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 electricity sales at Newfoundland Power for the quarter and at
FortisBC Electric, Caribbean Utilities and FortisOntario for the quarter
and year-to-date 2012
Unfavourable
-- Increased fuel prices at Caribbean Utilities and increased purchased
power costs at FortisBC Electric and FortisOntario
-- An increase in the basic component of customer rates at Maritime
Electric for the quarter associated with the higher flow through and
recovery of energy supply costs, partially offset by lower purchased
power costs at the utility
-- Increased electricity sales at Newfoundland Power and Fortis Turks and
Caicos year to date and at Maritime Electric for the quarter and year-
to-date 2012
-- Approximately $2 million for the quarter and $2 million year to date
associated with unfavourable foreign currency translation
Factors Contributing to Quarterly and Year-to-Date
Operating Expenses Variances
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. Non-ARO removal costs were recorded in
operating expenses in 2011.
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for the utility, effective
June 20, 2011
-- The cumulative $1.5 million ($1 million after tax) impact of the
increase in the allowed ROE at Newfoundland Power, effective January 1,
2012, was accrued in the second quarter of 2012 as a decrease in
operating expenses.
Unfavourable
-- General inflationary and employee-related cost increases at the
Corporation's regulated utilities, and timing of expenditures at
FortisBC Electric year-to-date 2012 and at FortisOntario for the quarter
and year-to-date 2012
-- Operating expenses associated with the Hilton Suites Winnipeg Airport
hotel, which was acquired in October 2011
Factors Contributing to Quarterly and Year-to-Date
Depreciation and Amortization Costs Variances
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
-- Decreased depreciation at FortisAlberta, mainly due to lower
depreciation rates effective January 1, 2012, as a result of the 2012
revenue requirements decision received in April 2012. Approximately $3
million of reduced depreciation in the second quarter of 2012 related to
the first quarter of 2012.
-- Lower depreciation rates at FortisBC Electric
Factors Contributing to Quarterly and Year-to-Date
Other Income (Expenses), Net Variances
Unfavourable
-- Approximately $4 million ($3 million after tax) and $8 million ($7
million after tax) of costs incurred in the second quarter and first
half of 2012, respectively, 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 million gain on the sale of property at FortisAlberta
during the first quarter of 2011
Favourable
-- An approximate $2 million and $0.5 million net foreign exchange gain for
the second quarter and first half of 2012, respectively, 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
Factors Contributing to Quarterly and Year-to-Date
Finance Charges Variances
Favourable
-- Higher capitalized interest associated with the financing of the
construction of the Corporation's 51% controlling ownership interest in
the Waneta Expansion hydroelectric generating facility ("Waneta
Expansion")
-- 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, driven by the
FortisBC Energy companies
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 Quarterly and Year-to-Date
Income Taxes Variances
Favourable
-- Lower statutory corporate income tax rates and higher earnings from non-
taxable foreign subsidiaries
-- Differences in the deductions for income tax purposes compared to
accounting purposes period over period
Unfavourable
-- An increase in Part VI.1 tax
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Increased earnings at FortisAlberta due to higher net transmission
revenue and lower depreciation expense as approved by the regulator, and
rate base growth, partially offset by a lower allowed ROE
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
-- Higher earnings at Newfoundland Power, mainly due to lower effective
income taxes and a higher allowed ROE. The cumulative approximate $1.5
million ($1 million after tax) impact of the increase in the allowed
ROE, effective January 1, 2012, was accrued in the second quarter of
2012.
Unfavourable
-- Higher corporate expenses due to approximately $4 million ($3 million
after tax) of costs incurred during the second quarter of 2012 related
to the pending acquisition of CH Energy Group and a lower income tax
recovery, partially offset by a net foreign exchange gain of
approximately $2 million recognized in the second quarter of 2012
-- Decreased earnings at the FortisBC Energy companies, mainly due to
lower-than-expected customer additions and lower capitalized AFUDC in
2012, partially offset by higher-than-expected gas transportation
volumes to industrial customers
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Increased earnings at FortisAlberta due to rate base growth, higher net
transmission revenue and lower effective income taxes, partially offset
by a lower allowed ROE and an approximate $1 million gain on the sale of
property during the first quarter of 2011
-- Increased earnings at the FortisBC Energy companies, mainly due to rate
base growth, seasonality of gas consumption and the timing of certain
expenses in 2012 and higher-than-expected gas transportation volumes to
industrial customers. The increase was partially offset by lower-than-
expected customer additions and lower capitalized AFUDC in 2012.
-- Increased non-regulated hydroelectric production in Belize, due to
higher rainfall
-- Increased earnings at Newfoundland Power, for the same reasons discussed
above for the quarter, combined with growth in electricity sales year to
date
Unfavourable
-- Higher corporate expenses, due to approximately $8 million ($7 million
after tax) of costs incurred during the first half of 2012 related to
the pending acquisition of CH Energy Group and a lower income tax
recovery, partially offset by lower finance charges
-- Decreased earnings at FortisBC Electric, due to the expiry of the
performance-based rate-setting ("PBR") mechanism on December 31, 2011
and lower capitalized AFUDC, partially offset by rate base growth
SEGMENTED RESULTS OF OPERATIONS
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -
Canadian
FortisBC Energy
Companies 13 15 (2) 95 90 5
----------------------------------------------------------------------------
Regulated Electric
Utilities - Canadian
FortisAlberta 26 18 8 47 39 8
FortisBC Electric 9 9 - 25 28 (3)
Newfoundland Power 12 10 2 19 16 3
Other Canadian Electric
Utilities 5 6 (1) 12 12 -
----------------------------------------------------------------------------
52 43 9 103 95 8
----------------------------------------------------------------------------
Regulated Electric
Utilities - Caribbean 6 6 - 9 10 (1)
Non-Regulated - Fortis
Generation 5 2 3 10 5 5
Non-Regulated - Fortis
Properties 8 8 - 9 9 -
Corporate and Other (22) (17) (5) (43) (36) (7)
----------------------------------------------------------------------------
Net Earnings Attributable
to Common Equity
Shareholders 62 57 5 183 173 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
Gas Volumes by Major Customer Category (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
(TJ) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Core - Residential
and Commercial 21,508 24,951 (3,443) 70,040 75,399 (5,359)
Industrial 1,071 1,229 (158) 2,842 3,117 (275)
----------------------------------------------------------------------------
Total Sales Volumes 22,579 26,180 (3,601) 72,882 78,516 (5,634)
Transportation
Volumes 16,774 16,730 44 38,243 37,214 1,029
Throughput under
Fixed Revenue
Contracts 93 489 (396) 700 965 (265)
----------------------------------------------------------------------------
Total Gas Volumes 39,446 43,399 (3,953) 111,825 116,695 (4,870)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver
Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI")
Factors Contributing to Quarterly and Year-to-Date
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 to industrial customers, due to some
customers switching to natural gas from alternative sources of fuel as a
result of lower natural gas prices, and continued high demand from the
mining sector
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, the FortisBC Energy companies adjusted their
combined customer count downwards by approximately 18,000, effective January 1,
2012. As at June 30, 2012, the total number of customers served by the FortisBC
Energy companies was approximately 937,000.
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.
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 264 319 (55) 812 893 (81)
Earnings 13 15 (2) 95 90 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Unfavourable
-- Lower commodity cost of natural gas charged to customers
-- Lower average gas consumption by residential and commercial customers
-- Lower-than-expected customer additions in 2012
Favourable
-- A net increase in the delivery component of customer rates, effective
January 1, 2012, mainly due to ongoing investment in energy
infrastructure and forecasted higher expenses recoverable from customers
and reflecting the 2012/2013 revenue requirements decision received by
the FortisBC Energy companies in April 2012
-- Higher-than-expected gas transportation volumes to industrial customers
in 2012
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Lower-than-expected customer additions in 2012
-- Lower capitalized AFUDC, due to a lower asset base under construction in
2012
Favourable
-- Higher-than-expected gas transportation volumes to industrial customers
in 2012
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- 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, which, combined with an approved
increase in expenses in 2012, has resulted in favourable timing
differences contributing to higher earnings year to date compared to the
same period last year
-- Higher-than-expected gas transportation volumes to industrial customers
in 2012
Unfavourable
-- The same factors discussed above for the quarter
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries
(gigawatt hours
("GWh")) 3,853 3,822 31 8,335 8,224 111
Revenue ($ millions) 110 103 7 218 203 15
Earnings ($ millions) 26 18 8 47 39 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly and Year-to-Date
Energy Deliveries Variances
Favourable
-- Growth in the number of customers, with the total number of customers
increasing by approximately 9,200 year over year as at June 30, 2012,
driven by favourable economic conditions
-- Higher average consumption by oilfield and commercial customers, due to
increased activity mainly as a result of higher market prices for oil
Unfavourable
-- Lower average consumption by residential, farm and irrigation customers,
due to warmer temperatures during the first four months of 2012 and
above-average precipitation levels during the second 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 Quarterly Revenue Variance
Favourable
-- An increase in customer electricity distribution rates, effective
January 1, 2012, driven primarily by ongoing investment in energy
infrastructure and forecasted certain higher expenses recoverable from
customers
-- Approximately $3 million of net transmission revenue recognized in the
second quarter of 2012, of which approximately $1 million related to the
first quarter of 2012. In its April 2012 distribution revenue
requirements decision, the regulator did not approve the continuation of
the deferral of transmission volume variances associated with
FortisAlberta's Alberta Electric System Operator ("AESO") charges
deferral account. In the absence of full deferral, FortisAlberta is
subject to volume risk on actual transmission costs relative to those
charged to customers based on forecast volumes and price. Net
transmission revenue is influenced by many factors, which may result in
actual transmission volumes varying from those that were forecast.
-- Growth in the number of customers
Unfavourable
-- The recognition in the second quarter of 2011 of accrued revenue related
to the cumulative 2010 and year-to-date 2011 allowed debt return and
recovery of depreciation on the additional $22 million in capital
expenditures approved by the regulator to be included in rate base
associated with the Automated Metering Project, which had the impact of
reducing revenue by approximately $2 million period over period.
-- A lower allowed ROE. 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 Year-to-Date Revenue Variance
Favourable
-- The same factors discussed above for the quarter
-- An approximate $2 million increase in franchise fee revenue
Unfavourable
-- The same factors discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Approximately $3 million of net transmission revenue recognized in the
second quarter of 2012, of which approximately $1 million related to the
first quarter of 2012, as a result of the 2012 distribution revenue
requirements decision received in April 2012
-- Rate base growth, due to continued investment in energy infrastructure
-- Reduced depreciation expense, due to the recognition in the second
quarter of 2012 of the cumulative impact of an overall decrease in
depreciation rates, effective January 1, 2012, as a result of the 2012
distribution revenue requirements decision received in April 2012.
Approximately $3 million of reduced depreciation expense in the second
quarter of 2012 related to the first quarter of 2012.
Unfavourable
-- A lower allowed ROE, as discussed above
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
-- Approximately $3 million of net transmission revenue recognized in the
second quarter of 2012, as a result of the 2012 distribution revenue
requirements decision received in April 2012
-- Lower effective income taxes, due to additional loss carryforwards being
utilized in FortisAlberta's 2011 income tax return filed in 2012, which
decreased income tax expense in 2012, and higher income taxes in 2011
related to the sale of property
Unfavourable
-- The same factor discussed above for the quarter
-- An approximate $1 million gain on the sale of property during the first
quarter of 2011
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 676 682 (6) 1,585 1,587 (2)
Revenue ($ millions) 67 65 2 154 148 6
Earnings ($ millions) 9 9 - 25 28 (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 Quarterly and Year-to-Date
Electricity Sales Variances
Unfavourable
-- Lower average energy consumption, due to differences in weather
conditions
Favourable
-- Growth in the number of customers
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
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
-- Differences in the amount of PBR incentive and flow-through adjustments
owing to customers period over period
Unfavourable
-- The 0.9% and 0.1% decrease in electricity sales for the quarter and year
to date, respectively
Factors Contributing to Quarterly and Year-to-Date
Earnings Variances
Unfavourable
-- The expiry of the PBR mechanism on December 31, 2011. During the first
half 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 electricity revenue, purchased power
costs and certain other costs and those used in determining customer
electricity rates are subject to full deferral account treatment and,
therefore, did not impact FortisBC Electric's earnings for the first
half of 2012.
-- Lower capitalized AFUDC, due to a lower asset base under construction in
2012
Favourable
-- Rate base growth, due to continued investment in energy infrastructure
NEWFOUNDLAND POWER
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 1,259 1,269 (10) 3,173 3,103 70
Revenue ($ millions) 130 133 (3) 322 316 6
Earnings ($ millions) 12 10 2 19 16 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Factors Contributing to Quarterly Electricity Sales Variance
Unfavourable
-- Sunnier weather conditions, which reduced average energy consumption
Favourable
-- Growth in the number of customers
Factors Contributing to Year-to-Date Electricity Sales Variance
Favourable
-- Growth in the number of customers
-- Higher concentration of electric-versus-oil heating in new home
construction combined with economic growth, which increased energy
consumption
Unfavourable
-- Sunnier weather conditions in the second quarter of 2012, which reduced
average energy consumption
Factors Contributing to Quarterly Revenue Variance
Unfavourable
-- Revenue during the first half 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.
-- The 0.8% decrease in electricity sales
Factors Contributing to Year-to-Date Revenue Variance
Favourable
-- The 2.3% increase in electricity sales
Unfavourable
-- The impact of the support structure arrangements with Bell Aliant during
2011, as discussed above for the quarter
Factors Contributing to Quarterly Earnings Variance
Favourable
-- Lower effective income taxes, primarily due to a lower allocation of
Part VI.1 tax to Newfoundland Power and a lower statutory income tax
rate
-- A higher allowed ROE. The cumulative approximate $1.5 million ($1
million after tax) impact of the increase in the allowed ROE, effective
January 1, 2012, was accrued in the second quarter of 2012 as a decrease
in operating expenses.
Unfavourable
-- The impact of the support structure arrangements with Bell Aliant during
2011, as discussed above
-- Higher depreciation expense, due to continued investment in energy
infrastructure
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- The same factors discussed above for the quarter
-- Electricity sales growth
Unfavourable
-- The same factors discussed above for the quarter
OTHER CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales
(GWh) 563 562 1 1,208 1,216 (8)
Revenue ($ millions) 82 78 4 173 169 4
Earnings ($ millions) 5 6 (1) 12 12 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly
includes Canadian Niagara Power, Cornwall Electric and Algoma Power.
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
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 residential customers and commercial
customers in the agricultural processing sector on PEI, primarily during
the first quarter of 2012
Unfavourable
-- Lower average consumption by residential and industrial customers in
Ontario, primarily during the first quarter of 2012, reflecting more
moderate temperatures and weak economic conditions in the region
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Favourable
-- Increased electricity sales on PEI, for the reasons discussed above
-- An increase in the basic component of customer rates at Maritime
Electric, effective March 1, 2012, associated with the higher flow
through and recovery of energy supply costs
-- The flow through in customer electricity rates of higher energy supply
costs at FortisOntario
Unfavourable
-- Decreased electricity sales in Ontario, for the reason discussed above
Factor Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher operating expenses at FortisOntario, mainly during the second
quarter of 2012, largely due to an increase in employee-related costs
and the timing of expenses during 2012
Factors Contributing to Year-to-Date Earnings Variance
Favourable
-- Increased electricity sales on PEI
Unfavourable
-- The same factor discussed above for the quarter
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN
Exchange Rate (2) 1.00 0.99 0.01 1.00 0.99 0.01
----------------------------------------------------------------------------
Electricity Sales
(GWh) 184 383 (199) 350 547 (197)
Revenue ($ millions) 67 85 (18) 130 160 (30)
Earnings ($ millions) 6 6 - 9 10 (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 and
Note 19 to the interim unaudited consolidated financial statements for
the three and six months ended June 30, 2012.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar. The reporting currency of Belize Electricity
was the Belizean dollar, which is pegged to the US dollar at
BZ$2.00=US$1.00.
Factors Contributing to Quarterly and Year-to-Date
Electricity Sales Variances
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 decreased
approximately 2.6% for the quarter and 0.8% year to date.
-- Higher rainfall experienced on Grand Cayman, which decreased air
conditioning load
Favourable
-- Growth in the number of customers on Grand Cayman and the Turks and
Caicos Islands
-- Warmer temperatures experienced on the Turks and Caicos Islands, which
increased air conditioning load
-- A strong tourist season year to date on the Turks and Caicos Islands
Factors Contributing to Quarterly and Year-to-Date
Revenue Variances
Unfavourable
-- The expropriation of Belize Electricity and the resulting discontinuance
of the consolidation method of accounting for Belize Electricity,
effective June 20, 2011
-- Decreased electricity sales at Caribbean Utilities
-- The discontinuance of government subsidization of Fortis Turks and
Caicos' South Caicos operations, effective April 1, 2012, in accordance
with a rate decision received in February 2012
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
-- Increased base electricity rates of 0.7% at Caribbean Utilities,
effective June 1, 2012
-- Increased electricity sales at Fortis Turks and Caicos
-- An increase in electricity rates for Fortis Turks and Caicos' large
hotel customers effective, April 1, 2012, in accordance with a rate
decision received in February 2012
-- Approximately $3 million for the quarter and $4 million year to date of
favourable foreign exchange associated with the translation of US
dollar-denominated revenue, due to the strengthening of the US dollar
relative to the Canadian dollar period over period
Factors Contributing to Quarterly Earnings Variance
Unfavourable
-- Higher depreciation expense and finance charges, excluding Belize
Electricity, largely due to investment in utility capital assets
-- Decreased electricity sales at Caribbean Utilities
Favourable
-- Lower energy supply costs at Fortis Turks and Caicos, mainly due to more
fuel-efficient production realized with the commissioning of new
generation units at the utility
-- Lower operating expenses at Caribbean Utilities, due to the timing of
capital projects and decreased legal and certain administrative expenses
-- Increased electricity sales at Fortis Turks and Caicos
Factors Contributing to Year-to-Date Earnings Variance
Unfavourable
-- The same factors discussed above for the quarter
-- Increased operating expenses at Fortis Turks and Caicos, mainly
associated with the timing of capital projects and higher insurance
expense
Favourable
-- Lower energy supply costs at Fortis Turks and Caicos, for the same
reason discussed above for the quarter
-- Increased electricity sales at Fortis Turks and Caicos
-- Lower operating expenses at Caribbean Utilities, for the same reason
discussed above for the quarter, partially offset by increased employee-
related and pension costs
NON-REGULATED - FORTIS GENERATION (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh) 87 90 (3) 175 166 9
Revenue ($ millions) 9 7 2 18 14 4
Earnings ($ millions) 5 2 3 10 5 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the financial results of non-regulated generation assets in
Belize, Ontario, central Newfoundland, British Columbia and Upstate New
York, with a combined generating capacity of 139 MW, mainly
hydroelectric.
Factors Contributing to Quarterly and Year-to-Date
Energy Sales Variances
Unfavourable
-- Decreased production in Upstate New York, due to a generating facility
being out of service and lower rainfall
-- Decreased production in Ontario, due to lower rainfall
Favourable
-- Increased production in Belize, due to higher rainfall
Factor Contributing to Quarterly and Year-to-Date
Revenue and Earnings Variances
Favourable
-- Increased production in Belize
In May 2011 the generator at Moose River's hydroelectric generating facility in
Upstate New York sustained electrical damage. Repairs to the generator were
completed in the second quarter of 2012 but another repair continues to keep the
generating facility offline. Revenue for the first half of 2012 reflected
insurance amounts received related to the loss of earnings during the period in
the first half of 2012 when generator was being repaired.
NON-REGULATED - FORTIS PROPERTIES (1)
----------------------------------------------------------------------------
Financial Highlights
(Unaudited) Quarter Year-to-Date
Periods Ended June 30 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality - Revenue
per Available Room
("RevPAR") ($) 85.56 83.57 1.99 76.05 73.41 2.64
Real Estate - Occupancy
Rate (as at, %) 91.7 93.4 (1.7) 91.7 93.4 (1.7)
----------------------------------------------------------------------------
Hospitality Revenue ($
millions) 47 43 4 82 76 6
Real Estate Revenue ($
millions) 17 17 - 34 34 -
----------------------------------------------------------------------------
Total Revenue ($
millions) 64 60 4 116 110 6
----------------------------------------------------------------------------
Earnings ($ millions) 8 8 - 9 9 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Quarterly and Year-to-Date
Revenue Variances
Favourable
-- A 2.4% and 3.6% increase in RevPAR at the Hospitality Division for the
quarter and year to date, respectively, 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 $84.21 for the second quarter of 2012, an increase of 0.8% quarter
over quarter. The increase in RevPAR was due to an overall 2.3% increase
in the average daily room rate, partially offset by an overall 1.5%
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.
-- Excluding the impact of the Hilton Suites Winnipeg Airport hotel, RevPAR
was $74.53 year-to-date 2012, an increase of 1.5% period over period.
The increase in RevPAR was due to an overall 2.6% increase in the
average daily room rate, partially offset by an overall 1.1% 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 Quarterly and Year-to-Date
Earnings Variances
Favourable
-- Contribution from the Hilton Suites Winnipeg Airport hotel
Unfavourable
-- A $0.5 million gain on the sale of the Viking Mall during the first
quarter of 2011
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue 7 7 - 13 13 -
Operating Expenses 3 3 - 6 5 1
Depreciation and
Amortization - - - 1 1 -
Other Income (Expenses),
Net (3) - (3) (8) - (8)
Finance Charges 12 12 - 23 26 (3)
Income Tax Recovery (1) (3) 2 (5) (6) 1
----------------------------------------------------------------------------
(10) (5) (5) (20) (13) (7)
Preference Share Dividends 12 12 - 23 23 -
----------------------------------------------------------------------------
Net Corporate and Other
Expenses (22) (17) (5) (43) (36) (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Quarterly and Year-to-Date
Net Corporate and Other Expenses Variances
Unfavourable
-- Increased other expenses, net of other income, driven by approximately
$4 million ($3 million after tax) and $8 million ($7 million after tax)
of costs incurred during the second quarter and first half of 2012,
respectively, related to the pending acquisition of CH Energy Group. The
increases were partially offset by net foreign exchange gains of
approximately $2 million and $0.5 million for second quarter and first
half of 2012, respectively, 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.
-- Lower income tax recovery, primarily due to higher Part VI.1 tax
Favourable
-- Lower finance charges year to date, primarily due to higher capitalized
interest associated with the financing of the construction of the
Corporation's 51% controlling ownership interest in the Waneta Expansion
REGULATORY HIGHLIGHTS
The nature of regulation and material regulatory decisions and applications
associated with each of the Corporation's regulated gas and electric utilities
for the first half of 2012 are summarized as follows.
NATURE OF REGULATION
---------------------------------------------------------------------------
Allowed Returns (%) Supportive Features
------------------------------------------
Regulated Regulatory Allowed Future or Historical
Utility Authority Common 2010 2011 2012 Test Year
Equity Used to Set Customer
(%) Rates
---------------------------------------------------------------------------
ROE COS/ROE
---------------------
FEI British 40 9.50 9.50 9.50 FEI: Prior to January
Columbia 1, 2010, 50/50
Utilities sharing of earnings
Commission above or below the
("BCUC") 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 ROE established by
("AUC") the AUC
---------------------
Future Test Year
---------------------------------------------------------------------------
Newfound- Newfoundland 45 9.00 8.38 8.80 COS/ROE
land and Labrador +/- +/- +/-
Power Board of 50 bps 50 bps 50 bps The allowed ROE is
Commissioners set using an
of Public automatic adjustment
Utilities formula tied to long-
("PUB") term Canada bond
yields. The formula
was 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
Board
("OEB")
Canadian 40 8.01 8.01 8.01 Algoma Power -
Niagara (1) COS/ROE and
Power subject to Rural and
Remote Rate
Algoma Power 40 8.57 9.85 9.85 Protection ("RRRP")
(1) Program
Franchise Cornwall Electric -
Agreement Price cap with
Cornwall commodity cost flow
Electric 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
---------------------------------------------------------------------------
ROA COS/ROA
---------------------
Caribbean Electricity N/A 7.75 - 7.75 - 7.25 -
Utilities Regulatory 9.75 9.75 9.25 Rate-cap adjustment
Authority mechanism based on
("ERA") 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 17.50 17.50 COS/ROA
Turks make (2) (2) (2)
and Caicos annual
filings
to the
Interim If the actual ROA is
Government lower than the
of the Turks allowed ROA, due to
and Caicos additional costs
Caicos resulting from a
Islands hurricane or other
("Interim event, the Company
Government") may apply for an
increase in customer
rates in the
following year.
---------------------
Future Test Year
---------------------------------------------------------------------------
(1) 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.
(2) 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 Utility Summary Description
----------------------------------------------------------------------------
FEI/FEVI/FEWI - FEI and FEWI review with the BCUC natural gas 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 contracting for midstream resources, such
as third-party pipeline and/or storage capacity. The
commodity cost of natural gas 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%, 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.
- Effective June 1, 2012, the delivery component of rates
decreased approximately 1.4% for FEI customers in the
Lower Mainland, Fraser Valley and Interior, North and
Kootenay service areas and for FEWI customers in Whistler,
as a result of the BCUC's final decision on the utilities'
2012-2013 RRAs.
- Natural gas commodity rates were unchanged, effective
July 1, 2012, 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 would have owned, operated and maintained
the new thermal plants and charged the Delta School
District a single rate for thermal energy consumed. In
March 2012 the BCUC issued its decision granting 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. FEI has complied with the condition.
In June 2012 the BCUC approved the rate design for the
project.
- 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 fuelling 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 application was issued by the BCUC in
April 2012 and, subsequently, in May 2012, the Government
of British Columbia issued the Greenhouse Gas Reduction
Regulation ("GHG Regulation") under the Clean Energy Act
(British Columbia). As a result of the GHG Regulation and
concerns FEI had with elements of the BCUC decision, FEI
sought reconsideration or variance of certain elements of
the decision. In July 2012 the BCUC issued a letter
confirming that the reconsideration application will be
heard.
- 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, 2014. In late 2011
the utilities temporarily suspended their application
while they provided 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.
Regulatory review of the application is underway.
- In November 2011 the BCUC issued preliminary
notification to public utilities subject to its
regulation, including the FortisBC gas and electric
utilities, that it would 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 GCOC Proceeding. In April 2012 the BCUC
issued a final scoping document outlining 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 retained an independent consultant to report on
regulatory practices in Canadian jurisdictions. The
preliminary timetable sets the evidence portion of the
GCOC Proceeding to take place through to early December
2012 with an oral hearing, if required, to commence on
December 12, 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
final approved increase in customer delivery rates,
effective January 1, 2012, was 4.2% at FEI, approximately
1.4% lower than the interim customer delivery rates. The
final approved increase in customer delivery rates,
effective January 1, 2012, was 3.6% at FEWI, approximately
1.4% lower than the interim customer delivery 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 is being refunded to customers,
which commenced June 1, 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.
- In May 2012 FortisBC Alternative Energy Services
("FAES") applied for a CPCN to construct and operate a
thermal energy system and for approval of associated
customer rates. The thermal energy system comprises a geo-
exchange ground loop, heat pumps, high-efficiency natural
gas boilers and ancillary equipment to provide space
heating, cooling and domestic hot water to PCI Marine
Gateway development tenants through an exclusive energy
supply arrangement. The thermal energy system will be
owned, operated and maintained by FAES. A written
regulatory review process has been established, which will
conclude at the end of August 2012 with a decision
expected in fall 2012.
- Following the announcement of the GHG Regulation by the
Government of British Columbia, FEI announced an incentive
funding program to assist heavy-duty fleet operators in
purchasing LNG-fuelled vehicles. The incentive program
funding includes up to $62 million to offset a percentage
of the incremental capital cost for qualifying LNG-fuelled
vehicles, up to $30 million for LNG fuelling stations and
up to $12 million for CNG fuelling stations. Incentives
are expected to be awarded beginning in 2012 and will
cover up to 80% of the eligible incremental capital costs.
The eligible applicants for this program are commercial,
return-to-base fleet operators of heavy-duty trucks,
buses, vocational vehicles and marine vessels. FEI will be
applying to the BCUC in 2012 to determine how these costs
are to be recovered from FEI's natural gas utility
customers.
----------------------------------------------------------------------------
FortisBC - In June 2011 FortisBC Electric filed its 2012-2013 RRA,
Electric which included its 2012-2013 Capital Expenditure Plan
("2012-2013 CEP") 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
between actual electricity revenue, purchased power costs
and certain other costs and those forecasted in
determining customer electricity rates.
- 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 in the third quarter of 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 and
submitted the agreement to the BCUC. 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. In May 2012 the BCUC determined that the executed
agreement is in the public interest and a hearing is not
required. The agreement has been accepted for filing as an
energy supply contract and FortisBC Electric has been
directed by the BCUC to develop a rate-smoothing proposal
as part of a separate submission or as part of FortisBC
Electric's next RRA.
- 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 permanently
disallowed from rate base and any resulting financial
impact. The hearing is expected to take place throughout
2012.
- In late July 2012, FortisBC Electric filed its Advanced
Metering Infrastructure ("AMI") application with the BCUC.
The AMI project proposes to improve and modernize FortisBC
Electric's grid by exchanging its manually read meters
with advanced meters. The AMI project is expected to cost
approximately $48 million and be completed in 2015. The
project was included in the utility's 2012-2013 CEP and
ISP.
----------------------------------------------------------------------------
FortisAlberta - 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
expected 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 outlined
its views as to how PBR should be implemented at
FortisAlberta. A hearing on the matter occurred during
April and May 2012, with a final argument submitted in
July 2012 and a decision on the matter expected in the
fourth quarter of 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 deemed equity component of FortisAlberta's capital
structure remains at 41%. 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 at a future proceeding.
- In March 2012 the AUC issued a bulletin regarding
maintaining regulated electricity rates. The bulletin
addressed the Government of Alberta's letter requesting
that regulated electricity rates be maintained until the
government responds to the recommendations of the Retail
Market Review Committee (the "Committee"), announced in
February 2012. The Committee's mandate includes the review
of the default electricity rate charged to customers who
do not obtain retail service from a retailer. The AUC will
continue processing applications and may approve
applications that maintain existing rates or propose rate
reductions; however, the AUC will not issue decisions that
result in rate increases. The Committee's recommendations
are not expected to be completed until September 2012.
- 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 June 2012 the AUC decided that it
would not permit a review and variance of the 2011 GCOC
decision but would examine the issue in a future
proceeding. The court process has been temporarily
adjourned pending the AUC's follow-up proceeding.
- In April 2012 the AUC approved, substantially as filed,
a Negotiated Settlement Agreement ("NSA") pertaining to
FortisAlberta's 2012 distribution revenue requirements
resulting in an average increase in customer distribution
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
cumulative impacts of the 2012 revenue requirements
decision were recorded in the second quarter of 2012. The
increase in customer rates was driven primarily by ongoing
investment in energy infrastructure, including increased
financing costs. The NSA provided for forecast midyear
rate base of $2,025 million. The AUC did not approve the
continuation of the deferral of transmission volume
variances associated with FortisAlberta's AESO charges
deferral account. This item will be examined by the AUC in
a future proceeding. In its PBR proposal, FortisAlberta
provided evidence that the discontinuance of the deferral
of transmission volume variances be reversed at the outset
of PBR in 2013.
- In July 2012 the AUC issued a decision denying an
application made by the Central Alberta Rural
Electrification Association ("CAREA") in which CAREA had
requested, effective January 1, 2012, that it 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 overlapping CAREA service area to only those customers
who are not being provided service by CAREA. The decision
confirms that FortisAlberta is the primary electricity
distribution service provider within its service
territory, including that portion of the Company's service
territory that overlaps with CAREA's service territory.
- In June 2012 AESO filed two applications with the AUC:
(i) the AESO Customer Contribution Policy Application; and
(ii) the Amortized Construction Contribution Rider I
Application. The first application proposes a reduction in
the level of AESO contributions that transmission
customers, including FortisAlberta, would pay versus what
the transmission facility owner would pay. The second
application proposes that transmission customers be given
the option to make the required AESO contributions as a
series of payments over a number of years, rather than as
an up-front payment. Effectively, this would result in the
transmission facility owner financing the AESO
contributions. A decision on the applications is not
expected until 2013.
----------------------------------------------------------------------------
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. In June 2012 the PUB ordered that the allowed
ROE for 2012 be increased to 8.80% from 8.38% for 2011.
The PUB also approved the deferred recovery of
approximately $2.5 million before tax, reflecting the
difference between the 8.38% allowed ROE currently
reflected in customer electricity rates in 2012 and the
final approved allowed ROE of 8.80%.
- In June 2012 Newfoundland Power filed an application
with the PUB requesting approval for its 2013 Capital
Expenditure Plan totalling approximately $83 million,
before customer contributions.
- Effective July 1, 2012, the PUB approved an overall
average increase in Newfoundland Power's customer
electricity rates of 6.6%. The increase in rates is
primarily due to the result of the normal annual operation
of the Newfoundland and Labrador Hydro ("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 Rate Stabilization Account ("RSA"). The operation
of the RSA further captures variances in certain of
Newfoundland Power's costs, such as pension and energy
supply costs. The increase in customer rates will not have
an impact on Newfoundland Power's earnings.
- As directed by the PUB, Newfoundland Power will be
filing a General Rate Application for 2013 customer
electricity rates during the third quarter of 2012.
----------------------------------------------------------------------------
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 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 New Brunswick
Power 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, 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.
- In June 2012 Maritime Electric filed its 2013 Capital
Budget Application totaling approximately $26 million,
before customer contributions.
- Maritime Electric intends to file an application for
2013 customer rates and allowed ROE with IRAC in fall
2012.
----------------------------------------------------------------------------
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.
- In May 2012 FortisOntario filed a COS Application for
electricity distribution rates in Fort Erie, Port Colborne
and Gananoque, effective January 1, 2013, using a 2013
forward test year. The application proposes an allowed ROE
of 9.12% on a deemed equity component of capital structure
of 40%. FortisOntario also filed with the COS Application
the quantification of an amount owing to customers related
to the disposal of an income tax-related regulatory
deferral account, as required by the OEB. The amount owing
to customers of approximately $1 million is expected to be
recognized by FortisOntario once a final decision is made
by the OEB on the amount owing, which is expected before
the end of 2012, and will have the impact of reducing
FortisOntario's earnings at that time.
----------------------------------------------------------------------------
Caribbean - In April 2012 the ERA approved Caribbean Utilities'
Utilities 2012-2016 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 is
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. Proposals for installation of the new
generation unit from six qualified bidders, including
Caribbean Utilities, was requested by the ERA and
Caribbean Utilities' proposal was submitted in July 2012.
The ERA's decision on the successful bidder is expected
during the second half of 2012. A second increment of 18
MW of new generating capacity is required up to three
years later in 2017, contingent on economic and load
growth over the next few 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
and other information and communication technology
services 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. The
reassignment of existing contracts is in progress and is
expected to be completed during the second half of 2012.
The ERA has approved executed management and maintenance,
pole attachment and fibre optic agreements between
Caribbean Utilities and DataLink.
- 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 renewable 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. The developers will finance,
construct, own and operate the renewable generation
facilities. Negotiations are ongoing towards firm power
purchase agreements with the developers. The power
purchase agreements, however, are subject to ERA review
and approval. Upon regulatory approval of negotiated power
purchase agreements, construction will commence. It is
anticipated that the projects will be completed within a
two-year period.
- Effective June 1, 2012, following review and approval by
the ERA, Caribbean Utilities' base customer electricity
rates increased by 0.7% as a result of changes in the
applicable consumer price indices and in the utility's
targeted allowed ROA for 2012.
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Fortis Turks - An independent review of the regulatory framework for
and Caicos the 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 in the third quarter of 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$72 million
as at December 31, 2011.
- In April 2012 Fortis Turks and Caicos entered into a
Streetlight Takeover Agreement with the Interim Government
whereby the responsibility for the ownership, installation
and maintenance of all streetlights in the utility's
service territory was transferred to Fortis Turks and
Caicos.
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CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance
sheets between June 30, 2012 and December 31, 2011.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
June 30, 2012 and December 31, 2011
----------------------------------------------------------------------------
Balance Sheet Increase/
Account (Decrease) Explanation
($ millions)
----------------------------------------------------------------------------
Cash and cash 144 The increase was driven by cash on hand at the
equivalents FortisBC Energy companies associated with a
portion of the proceeds received from an equity
injection by Fortis during the second quarter
of 2012 and seasonality of operations, and the
timing of cash payments at the Waneta Expansion
Limited Partnership (the "Waneta Partnership").
----------------------------------------------------------------------------
Accounts (129) The decrease was primarily due to the impact of
receivable a seasonal decrease in sales mainly at the
FortisBC Energy companies and Newfoundland
Power.
----------------------------------------------------------------------------
Inventories (27) The decrease was driven by the normal seasonal
reduction of gas in storage at the FortisBC
Energy companies.
----------------------------------------------------------------------------
Regulatory (40) The decrease was mainly due to the change in
assets the deferral of the fair market value of the
-current and natural gas derivatives at the FortisBC Energy
long-term companies and in the deferral of AESO charges
at FortisAlberta, partially offset by higher
regulatory deferred income taxes and an
increase in the deferral of various costs, as
permitted by the regulators, mainly at the
FortisBC Energy companies.
----------------------------------------------------------------------------
Other assets 29 The increase was mainly due to financing costs
associated with the Corporation's Subscription
Receipts offering, an increase in income taxes
receivable at Maritime Electric and an increase
in defined benefit pension assets at
Newfoundland Power.
----------------------------------------------------------------------------
Utility capital 267 The increase primarily related to $473 million
assets invested in electricity and gas systems,
partially offset by depreciation and customer
contributions for the six months ended June 30,
2012.
----------------------------------------------------------------------------
Short-term (78) The decrease was primarily due to a reduction
borrowings in borrowings at the FortisBC Energy companies
with a portion of the proceeds received from an
equity injection by Fortis during the second
quarter of 2012 and due to seasonality of
operations, partially offset by increased
borrowings at Caribbean Utilities, mainly to
repay maturing long-term debt.
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Accounts (127) The decrease was mainly due to: (i) the change
payable and in the fair market value of the natural gas
other current derivatives at the FortisBC Energy companies;
liabilities (ii) lower amounts owing for purchased natural
gas at the FortisBC Energy companies and
purchased power at Newfoundland Power,
associated with seasonality of operations; and
(iii) lower accounts payable at the Waneta
Partnership associated with the timing of
payments related to the construction of the
Waneta Expansion. The decrease was partially
offset by higher accounts payable associated
with transmission-connected projects at
FortisAlberta.
----------------------------------------------------------------------------
Regulatory 92 The increase was mainly due to an overall
liabilities - increase in deferrals at the FortisBC Energy
current and companies and an increase in the AESO charges
long-term deferral at FortisAlberta. The increase in
deferrals at the FortisBC Energy companies was
due to: (i) 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 six months
ended June 30, 2012; (ii) an increase in the
Rate Stabilization Deferral Account, reflecting
amounts collected in customer rates in excess
of the cost of providing service at FEVI during
the six months ended June 30, 2012; and (iii)
the provisioning for non-ARO removal costs
commencing January 1, 2012.
----------------------------------------------------------------------------
Deferred income 28 The increase was driven by tax timing
tax differences related to capital expenditures at
liabilities - the regulated utilities.
current and
long-term
----------------------------------------------------------------------------
Long-term debt 180 The increase was primarily due to higher
(including borrowings under the Corporation's committed
current credit facility to finance advances to the
portion) Waneta Partnership and an equity injection into
the FortisBC Energy companies, in support of
energy infrastructure investment, and for
general corporate purposes. The increase was
partially offset by regularly scheduled debt
repayments at Fortis Properties, the FortisBC
Energy companies and Caribbean Utilities.
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Shareholders' 106 The increase was primarily due to net earnings
equity attributable to common equity shareholders for
(before non- the six months ended June 30, 2012, less common
controlling share dividends, and the issuance of common
interests) shares under the Corporation's dividend
reinvestment plan.
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Non-controlling 67 The increase was driven by advances from the
interests 49% non-controlling interests in the Waneta
Partnership and an approximate $12 million, or
15%, equity investment by two First Nations
bands in the LNG storage facility on Vancouver
Island.
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LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's consolidated sources and uses of cash
for the three and six months ended June 30, 2012, as compared to the same
periods in 2011, followed by a discussion of the nature of the variances in cash
flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of Period 110 84 26 87 107 (20)
Cash Provided by (Used in):
Operating Activities 255 231 24 583 533 50
Investing Activities (273) (266) (7) (484) (483) (1)
Financing Activities 139 247 (108) 45 139 (94)
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Cash, End of Period 231 296 (65) 231 296 (65)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities was $24 million
higher quarter over quarter. The increase was primarily due to: (i) favourable
changes in working capital; (ii) the collection from customers of
regulator-approved increased depreciation and amortization costs, mainly at the
FortisBC Energy companies; and (iii) higher earnings. The favourable changes in
working capital quarter over quarter were associated with changes in accounts
receivable, partially offset by changes in accounts payable and other current
liabilities. The increase was partially offset by unfavourable changes in
long-term regulatory deferral accounts and a pension solvency deficit funding
payment made by Newfoundland Power during the second quarter of 2012.
Cash flow from operating activities was $50 million higher year to date compared
to the same period last year, due to the same factors discussed above for the
quarter. Favourable changes in working capital year to date compared to the same
period last year, however, were associated with changes in accounts receivable
and current regulatory deferral accounts, partially offset by changes in
inventories and accounts payable and other current liabilities.
Investing Activities: Cash used in investing activities was $7 million higher
for the quarter and $1 million higher year to date. Lower capital spending at
the FortisBC Energy companies, FortisBC Electric and the utilities in the
Caribbean for the quarter and year to date was largely offset by an increase in
capital spending at FortisAlberta for the quarter and year to date and an
increase in capital spending related to the non-regulated Waneta Expansion year
to date. Capital expenditures for the first half of 2011 included those of
Belize Electricity up to June 20, 2011, when the utility was expropriated by the
Government of Belize.
Cash used in investing activities also reflects the acquisition of the remaining
assets of Port Colborne Hydro by FortisOntario in April 2012 for approximately
$7 million.
Financing Activities: Cash provided by financing activities was $108 million
lower quarter over quarter. The decrease was primarily due to: (i) lower
proceeds from the issuance of common shares; (ii) higher repayments of long-term
debt; (iii) lower proceeds from long-term debt; (iv) lower advances from
non-controlling interests; (v) issue costs related to the June 2012 Subscription
Receipts offering; and (vi) higher common share dividends. The decrease was
partially offset by higher net borrowings under committed credit facilities
classified as long term and lower repayments of short-term borrowings.
Cash provided by financing activities was $94 million lower year to date
compared to the same period last year. The decrease was due to the same factors
discussed above for the quarter; however, advances from non-controlling
interests were higher year to date compared to the same period last year.
Net proceeds from short-term borrowings were $5 million for the quarter compared
to net repayments of short-term borrowings of $102 million for the same quarter
last year. Net repayments of short-term borrowings were $78 million year to date
compared to $200 million for the same period last year. The changes for the
quarter and year-to-date periods were driven by the FortisBC Energy companies
and Caribbean Utilities.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt
and capital lease and finance obligations, and net borrowings under committed
credit facilities for the quarter and year to date compared to the same periods
last year are summarized in the following tables.
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caribbean Utilities (1) - 29 (29) - 29 (29)
Other - 1 (1) - 1 (1)
----------------------------------------------------------------------------
Total - 30 (30) - 30 (30)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Issued in June 2011, 15-year US$11.25 million 4.85% and 20-year
US$18.75 million 5.10% unsecured notes. The net proceeds were used to
repay current installments on long-term debt and short-term borrowings
and to finance capital expenditures.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
(Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy
Companies (17) (1) (16) (18) (2) (16)
Caribbean Utilities (13) (12) (1) (13) (12) (1)
Fortis Properties (22) (2) (20) (24) (4) (20)
Other (1) (4) 3 (2) (6) 4
----------------------------------------------------------------------------
Total (53) (19) (34) (57) (24) (33)
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----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Borrowings Under Committed Credit Facilities (Unaudited)
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2012 2011 Variance 2012 2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta 38 5 33 9 17 (8)
FortisBC Electric 17 7 10 8 7 1
Newfoundland Power 14 10 4 28 23 5
Corporate 154 36 118 185 26 159
----------------------------------------------------------------------------
Total 223 58 165 230 73 157
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $27 million for the quarter and $56 million year to
date were received from non-controlling interests in the Waneta Partnership to
finance capital spending related to the Waneta Expansion, compared to $40
million received for the second quarter of 2011 and $57 million received
year-to-date 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.
In June 2011 Fortis issued 9.1 million common shares for gross proceeds of $300
million. The net proceeds of $288 million were used to repay borrowings under
credit facilities and finance equity injections into the utilities in western
Canada and the Waneta Expansion in support of infrastructure investment, and for
general corporate purposes.
Common share dividends paid during the second quarter of 2012 were $42 million,
net of $15 million in dividends reinvested, compared to $36 million, net of $15
million in dividends reinvested, paid during the same quarter of 2011. Common
share dividends paid in the first half of 2012 were $86 million, net of $28
million in dividends reinvested, compared to $71 million, net of $31 million in
dividends reinvested, paid in the first half of 2011. The dividend paid per
common share for the first and second quarters of 2012 was $0.30 compared to
$0.29 for the first and second quarters of 2011. The weighted average number of
common shares outstanding for the second quarter and year to date was 189.6
million and 189.3 million, respectively, compared to 177.1 million and 175.8
million for the second quarter and year to date, respectively, in 2011.
CONTRACTUAL OBLIGATIONS
As at June 30, 2012, consolidated contractual obligations of Fortis over the
next five years and for periods thereafter are outlined in the following table.
A detailed description of the nature of the obligations is provided in the 2011
Annual MD&A and below, where applicable. The presentation of certain contractual
obligations has changed from that provided in the 2011 Annual MD&A, due to the
adoption of US GAAP. For further information concerning these changes, refer to
the 2011 audited consolidated financial statements prepared in accordance with
US GAAP and voluntarily filed on SEDAR.
----------------------------------------------------------------------------
Contractual Obligations (Unaudited) Due Due in Due in Due
As at June 30, 2012 within years years after
($ millions) Total 1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt 5,968 90 775 610 4,493
Capital lease and finance
obligations (1) 2,609 47 97 100 2,365
Waneta Partnership promissory note 72 - - - 72
Gas purchase contract obligations
(2) 255 175 80 - -
Power purchase obligations
FortisBC Electric 23 12 8 3 -
FortisOntario 387 47 99 104 137
Maritime Electric 162 41 79 28 14
Capital cost 452 17 35 36 364
Joint-use asset and shared service
agreements 63 4 8 6 45
Operating lease obligations 25 5 7 6 7
Defined benefit pension funding
contributions (3) 92 34 39 17 2
Other 7 1 2 - 4
----------------------------------------------------------------------------
Total 10,115 473 1,229 910 7,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes principal payments, 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 June 30, 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 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 million, including interest, over five
years beginning in 2012, which is reflected in the above table. The
Company fulfilled its 2012 annual solvency deficit funding requirement
during the second quarter of 2012.
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.
Caribbean Utilities has a primary fuel supply contract with a major supplier and
is committed to purchasing approximately 80% of the Company's diesel fuel
requirements from this supplier for the operation of Caribbean Utilities'
diesel-powered generating plant. The contract contains an automatic renewal
clause for the years 2010 through to 2012. The approximate quantity per the
contract on an annual basis is 10.1 million imperial gallons for 2012. The
Company has renewed the contract to July 2012 and is in the process of
negotiating terms of a new contract.
In February 2012 Fortis entered into an agreement to acquire CH Energy Group for
US$1.5 billion, including the assumption of approximately US$500 million in debt
on closing. The acquisition is expected to close by the end of the first quarter
of 2013. In June 2012, to finance a portion of the purchase price of CH Energy
Group, Fortis sold 18,500,000 Subscription Receipts at $32.50 each resulting in
gross proceeds of approximately $601 million. Each Subscription Receipt will
entitle the holder thereof to receive, on satisfaction of the Release Conditions
and without payment of additional consideration, one common share of Fortis and
a cash payment equal to the dividends declared on Fortis common shares to
holders of record during the period from June 27, 2012 to the date of issuance
of the common shares in respect of the Subscription Receipts. For further
information on the pending acquisition of CH Energy Group and the Subscription
Receipts offering, refer to the "Corporate Overview" section of this MD&A.
For a discussion of the nature and amount of the Corporation's consolidated
capital expenditure program, which is not included in the Contractual
Obligations table above, refer to the "Capital Expenditure Program" section of
this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated gas and electricity
distribution require ongoing access to capital to enable the utilities to fund
maintenance and expansion of infrastructure. Fortis raises debt at the
subsidiary level to ensure regulatory transparency, tax efficiency and financing
flexibility. Fortis generally finances a significant portion of acquisitions at
the corporate level with proceeds from common share, preference share and
long-term debt offerings. To help ensure access to capital, the Corporation
targets a consolidated long-term capital structure containing approximately 40%
equity, including preference shares, and 60% debt, as well as investment-grade
credit ratings. Each of the Corporation's regulated utilities maintains its own
capital structure in line with the deemed capital structure reflected in each of
the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
June 30, 2012 December 31, 2011
($ millions) (%)($ millions) (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease
and finance obligations
(net of cash) (1) (2) 6,253 56.4 6,296 57.1
Preference shares 912 8.2 912 8.3
Common shareholders' equity 3,929 35.4 3,823 34.6
----------------------------------------------------------------------------
Total (3) 11,094 100.0 11,031 100.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes long-term debt and capital lease and finance obligations,
including current portion, and short-term borrowings, net of cash
(2) Excluding capital lease and finance obligations, the debt component of
the capital structure was 54.6% as at June 30, 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) an increase
in cash; (ii) lower short-term borrowings; (iii) net earnings attributable to
common equity shareholders, net of dividends; and (iv) common shares issued
mainly under the Corporation's dividend reinvestment plan. The capital structure
was also impacted by an increase in long-term debt, mainly due to higher
borrowings under the Corporation's committed credit facility in support of
utility infrastructure investment, partially offset by regularly scheduled debt
repayments.
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit
rating)
DBRS A(low) (unsecured debt credit rating)
In May 2012 and July 2012, S&P and DBRS, respectively, affirmed the
Corporation's debt credit ratings. Also, S&P and DBRS removed the ratings from
credit watch with negative implications and under review with developing
implications, respectively, where the ratings had been placed in February 2012,
mainly reflecting the Corporation's financing plans for the pending acquisition
of CH Energy Group and the expected completion of the Waneta Expansion on time
and on budget.
The above-noted 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.
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 $511 million in gross capital expenditures by segment for the
first half of 2012 is provided in the following table.
--------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date June 30, 2012
($ millions)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Other
Regulated Total
FortisBC Electric Regulated
Energy Fortis FortisBC Newfoundland Utilities - Utilities -
Companies Alberta (2) Electric Power Canadian Canadian
--------------------------------------------------------------------------
78 200 33 36 22 369
--------------------------------------------------------------------------
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----------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited)
(1)
Year-to-Date June 30, 2012
($ millions)
----------------------------------------------------
----------------------------------------------------
Regulated
Electric Non-
Utilities - Regulated - Fortis
Caribbean Utility (3) Properties Total
----------------------------------------------------
22 105 15 511
----------------------------------------------------
----------------------------------------------------
(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 a record of approximately $1.3 billion.
FEI's Customer Care Enhancement Project, at an estimated total project cost of
$110 million, came into service at the beginning of January 2012. Most of the
remaining $30 million of the project costs were incurred in the first half of
2012, with remaining smaller payments expected to be made during 2012.
Construction progress on the $900 million Waneta Expansion is going well and the
project is currently on schedule and on budget. Major construction activities
on-site include the completion of the excavation of the intake, powerhouse and
power tunnels. Approximately $345 million in total 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. The addition of CH Energy Group is expected
to add approximately $0.5 billion to the Corporation's consolidated capital
expenditure program from 2013 through 2016. Approximately 65% of the $5.5
billion capital program is expected to be incurred at the regulated electric
utilities, driven by FortisAlberta and FortisBC Electric. Approximately 21% and
14% of the capital program 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 excluding CH Energy Group, 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 June 30, 2012, management expects consolidated long-term debt maturities
and repayments to average approximately $295 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.
In May 2012 Fortis filed a base shelf prospectus under which Fortis may, from
time to time during the 25-month period from May 10, 2012, offer, by way of a
prospectus supplement, common shares, preference shares, subscription receipts
and/or unsecured debentures in the aggregate amount of up to $1.3 billion (or
the equivalent in US dollars or other currencies). The base shelf prospectus
provides the Corporation with flexibility to access securities markets in a
timely manner. The nature, size and timing of any offering of securities under
the Corporation's base shelf prospectus will be consistent with the past capital
raising practices of the Corporation and continue to be dependant upon the
Corporation's assessment of its requirements for funding and general market
conditions.
To finance a portion of the Corporation's pending acquisition of CH Energy
Group, Fortis offered and sold, by way of a prospectus supplement, approximately
$601 million in Subscription Receipts under a bought-deal offering with a
syndicate of underwriters. For further information refer to the "Corporate
Overview" section of this MD&A.
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 $55 million as at June 30, 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 19 to the Corporation's interim unaudited consolidated financial statements
for the three and six months ended June 30, 2012.
Except for the debt at the Exploits Partnership, as discussed above, Fortis and
its subsidiaries were in compliance with debt covenants as at June 30, 2012 and
are expected to remain compliant throughout the remainder of 2012.
CREDIT FACILITIES
As at June 30, 2012, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.5 billion, of which $2.0 billion was
unused, including $815 million unused under the Corporation's $1 billion
committed revolving corporate credit facility. The credit facilities are
syndicated mostly with the seven largest Canadian banks, with no one bank
holding more than 20% of these facilities. Approximately $2.3 billion of the
total credit facilities are committed facilities with maturities ranging from
2013 through 2017.
The following summary outlines the credit facilities of the Corporation and its
subsidiaries.
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Credit Facilities (Unaudited) As at
December
Regulated Fortis Corporate June 30, 31,
($ millions) Utilities Properties and Other 2012 2011
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Total credit
facilities 1,434 13 1,045 2,492 2,248
Credit facilities
utilized:
Short-term
borrowings (76) (5) - (81) (159)
Long-term debt
(including
current portion) (123) - (185) (308) (74)
Letters of credit
outstanding (67) - (1) (68) (66)
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Credit facilities
unused 1,168 8 859 2,035 1,949
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As at June 30, 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 revolving 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.
In May 2012 FHI extended its $30 million operating credit facility to mature in
May 2013 from May 2012. The new agreement contains substantially similar terms
and conditions as the previous credit facility agreement.
In May 2012 Fortis increased the amount available for borrowing under its
committed revolving corporate credit facility from $800 million to $1 billion,
as permitted under the credit facility agreement.
In May 2012 Caribbean Utilities renegotiated and increased the amount available
for borrowing under its unsecured credit facilities to US$47 million from US$33
million.
In June 2012 FortisOntario entered into a new short-term credit facility
agreement for $30 million replacing two short-term credit facilities totaling
$20 million. The new credit facility agreement reflects a decrease in pricing
and improved terms and conditions. In July 2012 the former credit facilities
were terminated.
In July 2012 FEI entered into a one-year extension of its $500 million unsecured
committed revolving credit facility agreement, amending the maturity date from
August 2013 to August 2014. The amended agreement reflects an increase in
pricing but, otherwise, contains substantially similar terms and conditions as
the previous credit facility agreement.
In July 2012 FortisAlberta renegotiated and amended its $250 million unsecured
committed revolving credit facility, obtaining an extension to the maturity of
the facility to August 2016 from September 2015 and a decrease in pricing. The
amended credit facility agreement otherwise contains substantially similar terms
and conditions as the previous credit facility agreement.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments
approximate their fair values, reflecting the short-term maturity, normal trade
credit terms and/or nature of these instruments, except as follows.
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Financial Instruments
(Unaudited) As at
June 30, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Waneta Partnership promissory
note 46 50 45 49
Long-term debt, including
current portion 5,968 7,394 5,788 7,172
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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 $106
million as at June 30, 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 and Belize Electric Company Limited is the US
dollar. Belize Electricity's financial results were denominated in Belizean
dollars, which are pegged to the US dollar.
As at June 30, 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 June 30,
2012, the Corporation had approximately US$13 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 gains and losses are also recorded in other comprehensive
income.
Effective June 20, 2011, the Corporation's asset associated with its 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 net
foreign exchange gain in earnings of approximately $2 million and $0.5 million
during the three and six months ended June 30, 2012, respectively.
From time to time, the Corporation and its subsidiaries hedge exposures to
fluctuations in interest rates, foreign exchange rates and fuel and natural gas
prices through the use of derivative financial instruments. The Corporation and
its subsidiaries do not hold or issue derivative financial instruments for
trading purposes. As at June 30, 2012, the Corporation's derivative contracts
consisted of fuel option contracts, natural gas swap and option contracts, and
gas purchase contract premiums. The fuel option contracts are held by Caribbean
Utilities and the remaining derivative instruments are held by the FortisBC
Energy companies.
The following table summarizes the Corporation's derivative financial instruments.
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Derivative Financial Instruments (Unaudited) As at
June 30, December 31,
2012 2011
Carrying Carrying
Number of Value (2) Value (2)
(Liability) Asset Maturity Contracts Volume (1) ($ millions) ($ millions)
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Foreign exchange
forward contract 2012 (3) - - - -
Fuel option
contracts 2013 4 4 (1) (1)
Natural gas
derivatives:
Swaps and
options 2014 90 39 (93) (135)
Gas purchase
contract
premiums 2014 46 91 3 -
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(1) The volume for fuel option contracts is reported in millions of gallons
and for natural gas derivatives is reported in petajoules.
(2) Carrying value is estimated fair value. The (liability) asset represents
the gross derivatives balance.
(3) The foreign exchange forward contract held by FEI expired in April 2012.
The carrying value of the contract was less than $1 million as at
December 31, 2011.
The fuel option contracts are used by Caribbean Utilities to reduce the impact
of volatility in fuel prices on customer rates, as approved by the regulator
under the Company's Fuel Price Volatility Management Program.
The natural gas derivatives held by the FortisBC Energy companies are used to
fix the effective purchase price of natural gas, as the majority of the natural
gas supply contracts at the FortisBC Energy companies have floating, rather than
fixed, prices. The price risk-management strategy of the FortisBC Energy
companies aims to improve the likelihood that natural gas prices remain
competitive, to mitigate 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 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.
The changes in the fair values of the fuel option contracts and natural gas
derivatives are deferred as a regulatory asset or liability for recovery from,
or refund to, customers in future rates, as permitted by the regulators. The
fair values of the derivative financial instruments were recorded in accounts
payable as at June 30, 2012 and as at December 31, 2011.
The fair value of the fuel option contracts reflects only the value of the
heating oil derivative and not the offsetting change in the value of the
underlying future purchases of heating oil and is calculated using published
market prices for heating oil. 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
fuel option contracts 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 $68 million, as at June
30, 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 half of 2012 from those disclosed in the 2011 Annual MD&A, except for
those described below.
Regulatory Risk: In April 2012 regulatory decisions were received for 2012 and
2013 customer gas delivery rates at the FortisBC Energy companies and for 2012
customer electricity distribution rates at FortisAlberta. The rate decisions
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: The acquisition of CH Energy
Group is subject to certain regulatory and other approvals. Failure to obtain,
or any delay in obtaining, such approvals could adversely impact the
Corporation's ability to close the acquisition or the timing of such closing. In
addition, 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 May 2012 and July
2012, S&P and DBRS, respectively, affirmed the Corporation's debt credit
ratings. Also, S&P and DBRS removed the ratings from credit watch with negative
implications and under review with developing implications, respectively, where
the ratings had been placed in February 2012, mainly reflecting the
Corporation's financing plans for the pending acquisition of CH Energy Group and
the expected completion of the Waneta Expansion on time and on budget.
Similarly, FortisAlberta's existing debt credit rating by S&P was confirmed in
May 2012 and removed from credit watch with negative implications. There were no
other changes in the credit ratings of the Corporation's utilities year-to-date
2012.
Power Supply and Capacity Purchase Contracts: In November 2011 FortisBC Electric
executed an agreement to purchase capacity from the Waneta Expansion and
submitted the agreement to the BCUC. 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. In May 2012 the BCUC
determined that the executed agreement is in the public interest and a hearing
is not required. The agreement has been accepted for filing as an energy supply
contract and FortisBC Electric has been directed by the BCUC to develop a rate
smoothing proposal as part of a separate submission or as part of FortisBC
Electric's next RRA.
Defined Benefit Pension Plan Assets: As at June 30, 2012, the fair value of the
Corporation's consolidated defined benefit pension plan assets was $826 million,
up $41 million or 5.2%, 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 on
January 31, 2011. A new agreement expiring in March 2014 has been reached with
regard to certain customer service employees. Discussions continue with regard
to certain support and technical employees.
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. A new four-year collective agreement, expiring in March
2015, was reached in June 2012.
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. One of the two newly negotiated collective
agreements was ratified during the first quarter of 2012; the other was ratified
in May 2012. The agreements are for three-year terms expiring in September 2014.
NEW 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 finance
obligations; (iv) reclassification of preference shares from long-term
liabilities to shareholders' equity; and (v) the calculation and recognition of
corporate income taxes based on enacted versus substantially enacted corporate
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 $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 $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 $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 corporate 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 and six months ended June 30,
2011, prepared in accordance with US GAAP versus Canadian GAAP, may be
summarized as follows:
-- Three Months Ended June 30, 2011 (Unaudited): Consolidated net earnings
recognized in accordance with US GAAP increased by $3 million, from $69
million to $72 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 $1 million.
-- Six months ended June 30, 2011 (Unaudited): Consolidated net earnings
recognized in accordance with US GAAP increased by $6 million, from $194
million to $200 million. The increase was due primarily to the
reclassification of preference share dividends totaling $8 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 $2 million.
New 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 estimated non-ARO removal
costs, net of salvage proceeds, were recognized in operating expenses 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. For the
three and six months ended June 30, 2012, non-ARO removal costs of $5 million
and $10 million, respectively, were accrued as a part of depreciation expense.
For the three and six months ended June 30, 2011, non-ARO removal costs of
approximately $4 million and $8 million, respectively, 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-noted 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 primarily a COS rate-setting methodology.
Beginning in 2012 variances between actual electricity revenue, purchased power
costs and certain other costs and those forecasted in determining customer
electricity rates 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 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 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 (i.e., 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 and six months
ended June 30, 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.
During the second quarter of 2012, the FortisBC Energy companies and
FortisAlberta received revenue requirements decisions, effective January 1,
2012, the cumulative impacts of which, where such impacts were different from
those estimated, were recorded in the second quarter of 2012. 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 half of 2012 from
those disclosed in the 2011 Annual MD&A except for that related to capital asset
depreciation. Changes in regulator-approved depreciation rates at FortisAlberta,
in conjunction with an approved depreciation study and revenue requirements
decision received in the second quarter of 2012, have impacted consolidated
depreciation expense. The composite depreciation rate for utility capital assets
at FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011. As required by
the BCUC, effective January 1, 2012, depreciation rates at the FortisBC Energy
companies now include an amount allowed for regulatory purposes to accrue for
estimated non-ARO removal costs, net of salvage proceeds. For further
information, refer to the "New Accounting Policies" section of this MD&A. The
impact of the above-noted changes in depreciation rates on depreciation expense
has been reflected in the utilities' approved revenue requirements and resulting
customer rates.
As part of its 2012-2013 RRA and depreciation study filed with the BCUC, which
are pending approval, FortisBC Electric's composite depreciation rate for
utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011, which has
impacted consolidated depreciation expense. The change in the composite
depreciation rate is subject to final approval by the BCUC.
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
In May 2012 CH Energy Group and Fortis entered into a proposed settlement
agreement with counsel to plaintiff shareholders pertaining to several
complaints, which named Fortis and other defendants, which were filed in, or
transferred to, the Supreme Court of the State of New York, County of New York,
relating to the proposed acquisition of CH Energy Group by Fortis. The
complaints generally alleged that the directors of CH Energy Group breached
their fiduciary duties in connection with the proposed acquisition and that CH
Energy Group, Fortis, FortisUS Inc. and Cascade Acquisition Sub Inc. aided and
abetted that breach. The settlement agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from Canada Revenue Agency 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. Following a mediation, in which FHI did not
participate, FHI was advised that all matters have now been settled.
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. A date for mediation of this matter has been
set for December 2012. The outcome cannot be reasonably determined and estimated
at this time and, accordingly, no amount has been accrued in the consolidated
financial statements.
The Government of British Columbia filed a claim in the British Columbia Supreme
Court in June 2012 claiming on its behalf, and on behalf of approximately 17
homeowners, damages suffered as a result of a landslide caused by a dam failure
in Oliver, British Columbia in 2010. The Government of British Columbia alleges
in its claim that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government of British
Columbia estimates its damages and the damages of the homeowners, on whose
behalf it is claiming, to be approximately $12 million. FortisBC Electric has
not been served, however, has retained counsel and has contacted its insurers.
The outcome cannot be reasonably determined and estimated at this time and,
accordingly, no amount has been accrued in the consolidated financial
statements.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the
eight quarters ended September 30, 2010 through June 30, 2012. The quarterly
information has been obtained from the Corporation's interim unaudited
consolidated financial statements, which have been prepared in accordance with
US GAAP. The timing of the recognition of certain assets, liabilities, revenue
and expenses, as a result of regulation, may differ from that otherwise expected
using US GAAP for non-regulated entities. The nature of regulation is further
disclosed in Notes 2, 3 and 7 to the Corporation's 2011 annual audited
consolidated financial statements prepared in accordance with US GAAP. The
quarterly financial results are not necessarily indicative of results for any
future period and should not be relied upon to predict future performance.
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Summary of Quarterly Results Net Earnings
(Unaudited) Attributable to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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June 30, 2012 792 62 0.33 0.33
March 31, 2012 1,149 121 0.64 0.62
December 31, 2011 1,034 82 0.44 0.43
September 30, 2011 699 56 0.30 0.30
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
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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 first and second quarters of
2012 were reduced by approximately $4 million and $3 million, respectively,
associated with costs incurred related to the pending acquisition of CH Energy
Group. During the second quarter of 2012, the FortisBC Energy companies and
FortisAlberta received revenue requirements decisions, effective from January 1,
2012, the cumulative impacts of which, where such impacts were different from
those estimated, were recorded in the second quarter of 2012. Financial results
from the fourth quarter ended December 31, 2011 reflected the acquisition of the
Hilton Suites Winnipeg Airport hotel in October 2011. 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 June 20, 2011 reflected the discontinuance of the
consolidation method of accounting for Belize Electricity due to the
expropriation of the utility by the Government of Belize. 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 and Note 19 to the interim unaudited consolidated financial statements for
the three and six months ended June 30, 2012. Revenue for the third quarter
ended September 30, 2010 reflected the favourable cumulative retroactive impact
associated with the 2010 revenue requirements decision at FortisAlberta.
June 2012/June 2011: Net earnings attributable to common equity shareholders
were $62 million, or $0.33 per common share, for the second quarter of 2012
compared to earnings of $57 million, or $0.32 per common share, for the second
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.
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. The increase in earnings was mainly due to higher contribution
from the FortisBC Energy companies, increased non-regulated hydroelectric
production in Belize, associated with higher rainfall, and higher earnings at
Newfoundland Power and Maritime Electric, mainly the result of increased
electricity sales and lower effective corporate income taxes. The increase in
earnings was partially offset by the impact of the expiry of the PBR mechanism
on December 31, 2011 at FortisBC Electric and the timing of certain operating
expenses at the utility in 2012, higher corporate expenses and an approximate $1
million gain on the sale of property at FortisAlberta during the first quarter
of 2011. The increase in earnings at the FortisBC Energy companies mainly
related to the seasonality of gas consumption and the timing of certain
operating expenses in 2012, rate base growth and higher gas transportation
volumes to industrial customers, partially offset by lower-than-expected
customer additions and lower capitalized AFUDC in 2012. The increase in
corporate expenses was the result of approximately $4 million of costs incurred
during the first quarter of 2012 related to the pending acquisition of CH Energy
Group and a $1.5 million foreign exchange loss associated with the previously
hedged investment in Belize Electricity, partially offset by lower finance
charges. An 8% increase in the weighted average number of common shares
outstanding quarter over quarter, largely associated with the issuance of common
equity mid-2011, had the impact of lowering earnings per common share in the
first quarter of 2012.
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 in 2011. The above-noted 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 issuance of common equity in mid-2011, had the
impact of lowering earnings per common share in the fourth quarter of 2011.
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. An 8% increase in the weighted
average number of common shares outstanding quarter over quarter, largely
associated with the issuance of common equity in mid-2011, had the impact of
lowering earnings per common share in the third quarter of 2011.
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 at the beginning
of 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 half of 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. The addition of CH Energy Group is expected to add
approximately $0.5 billion to the Corporation's consolidated capital expenditure
program from 2013 through 2016.
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 July 30, 2012, the Corporation had issued and outstanding approximately
190.0 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; 10.0 million First
Preference Shares, Series H; and 18.5 million Subscription Receipts. 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, First Preference Shares, Series C and E, and Subscription
Receipts were converted as at July 30, 2012 is as follows.
--------------------------------------------------------------
Conversion of Securities into Common Shares (Unaudited)
As at July 30, 2012 Number of
Common Shares
Security (millions)
--------------------------------------------------------------
--------------------------------------------------------------
Stock Options 5.2
First Preference Shares, Series C 4.0
First Preference Shares, Series E 6.3
Subscription Receipts 18.5
--------------------------------------------------------------
Total 34.0
--------------------------------------------------------------
--------------------------------------------------------------
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.
Interim Consolidated Financial Statements
For the three and six months ended June 30, 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)
June 30, December 31,
2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 21)
ASSETS
Current assets
Cash and cash equivalents $ 231 $ 87
Accounts receivable 509 638
Prepaid expenses 25 19
Inventories 107 134
Regulatory assets (Note 3) 122 219
Deferred income taxes 33 24
----------------------------
1,027 1,121
Other assets 213 184
Regulatory assets (Note 3) 1,457 1,400
Deferred income taxes 6 8
Utility capital assets 9,235 8,968
Income producing properties 599 594
Intangible assets 324 325
Goodwill (Note 12) 1,570 1,565
----------------------------
$ 14,431 $ 14,165
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 17) $ 81 $ 159
Accounts payable and other current liabilities 863 990
Regulatory liabilities (Note 3) 82 43
Current installments of long-term debt 90 103
Current installments of capital lease and
finance obligations 7 7
Deferred income taxes 2 5
----------------------------
1,125 1,307
Other liabilities 572 573
Regulatory liabilities (Note 3) 608 555
Deferred income taxes 704 673
Long-term debt 5,878 5,685
Capital lease and finance obligations 428 429
----------------------------
9,315 9,222
----------------------------
Shareholders' equity
Common shares (a)(Note 4) 3,071 3,036
Preference shares 912 912
Additional paid-in capital 15 14
Accumulated other comprehensive loss (94) (95)
Retained earnings 937 868
----------------------------
4,841 4,735
Non-controlling interests (Note 5) 275 208
----------------------------
5,116 4,943
----------------------------
$ 14,431 $ 14,165
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(a) no par value: unlimited authorized shares; 190.0 million and 188.8
million issued and outstanding as at June 30, 2012 and December 31, 2011,
respectively
Commitments and Contingent Liabilities (Notes 18 and 20, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars, except per share amounts)
Quarter Ended Six Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 792 $ 846 $ 1,941 $ 2,005
------------------------------------------------------
Expenses
Energy supply costs 291 358 857 961
Operating 204 209 418 419
Depreciation and
amortization 114 102 233 205
------------------------------------------------------
609 669 1,508 1,585
------------------------------------------------------
Operating income 183 177 433 420
Other income
(expenses), net (Note
8) - 4 (3) 12
Finance charges (Note
9) 92 93 183 185
------------------------------------------------------
Earnings before income
taxes 91 88 247 247
Income taxes (Note 10) 14 16 37 47
------------------------------------------------------
Net earnings $ 77 $ 72 $ 210 $ 200
------------------------------------------------------
------------------------------------------------------
Net earnings
attributable to:
Non-controlling
interests $ 3 $ 3 $ 4 $ 4
Preference equity
shareholders 12 12 23 23
Common equity
shareholders 62 57 183 173
------------------------------------------------------
$ 77 $ 72 $ 210 $ 200
------------------------------------------------------
------------------------------------------------------
Earnings per common
share (Note 11)
Basic $ 0.33 $ 0.32 $ 0.97 $ 0.98
Diluted $ 0.33 $ 0.32 $ 0.95 $ 0.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 77 $ 72 $ 210 $ 200
--------------------------------------------------------
--------------------------------------------------------
Other comprehensive
income (loss)
Unrealized foreign
currency
translation
gains (losses),
net of hedging
activities and
tax 2 - - (3)
Reclassification of
unrealized foreign
currency
translation
losses, net of
hedging
activities and
tax, related to
Belize
Electricity - 17 - 17
Unrealized employee
future benefits
gains,
net of tax - - 1 -
--------------------------------------------------------
2 17 1 14
--------------------------------------------------------
Comprehensive income$ 79 $ 89 $ 211 $ 214
--------------------------------------------------------
--------------------------------------------------------
Comprehensive income
attributable to:
Non-controlling
interests $ 3 $ 3 $ 4 $ 4
Preference equity
shareholders 12 12 23 23
Common equity
shareholders 64 74 184 187
--------------------------------------------------------
$ 79 $ 89 $ 211 $ 214
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter Ended Six Months Ended
2012 2011 2012 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 77 $ 72 $ 210 $ 200
Adjustments to
reconcile net
earnings to net
cash provided by
operating
activities:
Depreciation -
utility capital
assets and income
producing
properties 94 94 201 189
Amortization -
intangible assets 10 9 21 18
Amortization -
other 10 (1) 11 (2)
Deferred income
taxes 3 1 8 (1)
Accrued employee
future benefits (11) 5 (7) 9
Equity component
of allowance for
funds used
construction
(Note 8) (1) (3) (3) (8)
Other 3 5 (11) 4
Change in long-term
regulatory assets
and liabilities (13) - (9) 18
Change in non-cash
operating working
capital (Note 14) 83 49 162 106
--------------------------------------------------------
255 231 583 533
--------------------------------------------------------
Investing activities
Change in other
assets and other
liabilities - - 4 (2)
Capital expenditures
- utility capital
assets (262) (268) (473) (486)
Capital expenditures
- income producing
properties (10) (6) (15) (9)
Capital expenditures
- intangible assets (10) (12) (23) (23)
Contributions in aid
of construction 16 19 30 31
Proceeds on sale of
utility capital
assets and income
producing
properties - 1 - 6
Business acquisition
(Note 12) (7) - (7) -
--------------------------------------------------------
(273) (266) (484) (483)
--------------------------------------------------------
Financing activities
Change in short-term
borrowings 5 (102) (78) (200)
Proceeds from long-
term debt, net of
issue costs - 30 - 30
Repayments of long-
term debt and
capital lease and
finance obligations (53) (19) (57) (24)
Net borrowings under
committed credit
facilities 223 58 230 73
Advances from non-
controlling
interests 28 40 69 57
Subscription
Receipts issue
costs (Note 4) (12) - (12) -
Issue of common
shares, net of
costs and dividends
reinvested 4 290 6 301
Dividends
Common shares, net
of dividends
reinvested (42) (36) (86) (71)
Preference shares (12) (12) (23) (23)
Subsidiary
dividends paid to
non-controlling
interests (2) (2) (4) (4)
--------------------------------------------------------
139 247 45 139
--------------------------------------------------------
Change in cash and
cash equivalents 121 212 144 189
Cash and cash
equivalents,
beginning of period 110 84 87 107
--------------------------------------------------------
Cash and cash
equivalents, end of
period $ 231 $ 296 $ 231 $ 296
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
14)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Accumulated
Additional Other
Common Preference Paid-in Comprehensive Retained
Shares Shares Capital Loss Earnings
----------------------------------------------------------------------------
(Note 4)
As at December
31, 2011 $ 3,036 $ 912 $ 14 $ (95)$ 868
Net earnings - - - - 206
Other
comprehensive
income - - - 1 -
Common share
issues 35 - - - -
Stock-based
compensation - - 1 - -
Advances from
non-
controlling
interests - - - - -
Foreign
currency
translation
impacts - - - - -
Subsidiary
dividends paid
to non-
controlling
interests - - - - -
Dividends
declared on
common shares
($0.60 per
share) - - - - (114)
Dividends
declared on
preference
shares - - - - (23)
-------------------------------------------------------------
As at June 30,
2012 $ 3,071 $ 912 $ 15 $ (94)$ 937
----------------------------------------------------------------------------
As at December
31, 2010 $ 2,575 $ 912 $ 12 $ (108)$ 774
Net earnings - - - - 196
Other
comprehensive
income - - - 14 -
Common share
issues 337 - - - -
Stock-based
compensation - - 1 - -
Advances from
non-
controlling
interests - - - - -
Foreign
currency
translation
impacts - - - -
Subsidiary
dividends paid
to non-
controlling
interests - - - - -
Expropriation
of Belize
Electricity
(Notes 16, 17
and 19)
Dividends
declared on
common shares
($0.58 per
share) - - - - (105)
Dividends
declared on
preference
shares - - - - (23)
-------------------------------------------------------------
As at June 30,
2011 $ 2,912 $ 912 $ 13 $ (94)$ 842
----------------------------------------------------------------------------
Non-
Controlling
Interests Total Equity
--------------------------------------------
As at December
31, 2011 $ 208 $ 4,943
Net earnings 4 210
Other
comprehensive
income - 1
Common share
issues - 35
Stock-based
compensation - 1
Advances from
non-
controlling
interests 69 69
Foreign
currency
translation
impacts (2) (2)
Subsidiary
dividends paid
to non-
controlling
interests (4) (4)
Dividends
declared on
common shares
($0.60 per
share) - (114)
Dividends
declared on
preference
shares - (23)
-----------------------------
As at June 30,
2012 $ 275 $ 5,116
--------------------------------------------
As at December
31, 2010 $ 162 $ 4,327
Net earnings 4 200
Other
comprehensive
income - 14
Common share
issues - 337
Stock-based
compensation - 1
Advances from
non-
controlling
interests 57 57
Foreign
currency
translation
impacts (3) (3)
Subsidiary
dividends paid
to non-
controlling
interests (4) (4)
Expropriation
of Belize
Electricity
(Notes 16, 17
and 19) (38) (38)
Dividends
declared on
common shares
($0.58 per
share) - (105)
Dividends
declared on
preference
shares - (23)
-----------------------------
As at June 30,
2011 $ 178 $ 4,763
--------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 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 (Notes 16,
17 and 19).
NON-REGULATED - FORTIS GENERATION
Fortis Generation includes the financial results of non-regulated generation
assets in Belize, Ontario, central Newfoundland, British Columbia and Upstate
New York. Effective July 1, 2012, the legal ownership of the six small
non-regulated hydroelectric generating facilities in eastern Ontario, with a
combined generating capacity of 8 megawatts ("MW"), was transferred from Fortis
Properties to a limited partnership directly held by Fortis. FortisBC Electric
is assuming management responsibility for the operations of the above-noted
facilities, as well as for the four non-regulated hydroelectric generating
facilities in Upstate New York, with a combined generating capacity of 23 MW,
owned by FortisUS Energy Corporation ("FortisUS Energy").
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.
PENDING ACQUISITION
In February 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. 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 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 transaction received CH Energy Group shareholder
approval in June 2012 and regulatory approval from the Federal Energy Regulatory
Commission ("FERC") and the Committee on Foreign Investment in the United States
in July 2012.
The acquisition is also subject to certain other approvals, including approval
by the New York State Public Service Commission (the "NYSPSC"), and satisfaction
of customary closing conditions. The NYSPSC is currently reviewing the
application for approval of the transaction jointly filed by Fortis and CH
Energy Group in April 2012. The acquisition is expected to close by the end of
the first quarter of 2013 and be immediately accretive to earnings per common
share, excluding acquisition-related expenses.
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 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. During the second quarter of 2012,
the FortisBC Energy companies and FortisAlberta received 2012 revenue
requirements decisions, effective January 1, 2012, the cumulative impacts of
which, where such impacts were different from those estimated, were recorded in
the second quarter of 2012. Due to changes in facts and circumstances and the
inherent uncertainty involved in making estimates, actual results may differ
significantly from current estimates. Estimates and judgments are reviewed
periodically and, as adjustments become necessary, are reported in earnings in
the period in which they become known.
Interim financial statements may also employ a greater use of estimates than the
annual financial statements. There were no material changes in the nature of the
Corporation's critical accounting estimates during the three and six months
ended June 30, 2012, except as described below with respect to capital asset
depreciation.
An evaluation of subsequent events through July 30, 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 June 30, 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
(i.e., 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 interim consolidated financial
statements for the three and six months ended June 30, 2012.
New 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 ("RRAs") 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 estimated non-ARO removal costs, net of salvage proceeds,
were recognized in operating expenses 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. For the three and six months ended June 30, 2012,
non-ARO removal costs of approximately $5 million and $10 million, respectively,
were accrued as part of depreciation expense. For the three and six months ended
June 30, 2011, non-ARO removal costs of approximately $4 million and $8 million,
respectively, 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-noted sharing of positive or negative variances is no
longer in effect pursuant to the utility's filed 2012-2013 RRA, which is subject
to regulatory approval and reflects primarily a cost of service rate-setting
methodology. Beginning in 2012 variances between actual electricity revenue,
purchased power costs and certain other costs and those forecasted in
determining customer electricity rates 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.
Change in Estimates - Capital Asset Depreciation
Changes in regulator-approved depreciation rates at FortisAlberta, in
conjunction with an approved depreciation study and revenue requirements
decision received in the second quarter of 2012, have impacted consolidated
depreciation expense. The composite depreciation rate for utility capital assets
at FortisAlberta decreased to 4.0% for 2012 from 4.1% for 2011. As required by
the regulator, effective January 1, 2012, depreciation rates at the FortisBC
Energy companies now include an amount allowed for regulatory purposes to accrue
for estimated non-ARO removal costs, net of salvage proceeds. The impact of the
above-noted changes in depreciation rates on depreciation expense has been
reflected in the utilities' approved revenue requirements and resulting customer
rates.
As part of its 2012-2013 RRA and depreciation study filed with the regulator,
which are pending approval, FortisBC Electric's composite depreciation rate for
utility capital assets decreased to 3.1% for 2012 from 3.2% for 2011, which has
impacted consolidated depreciation expense. The change in the composite
depreciation rate is subject to final approval by the regulator.
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
June 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes 664 630
Employee future benefits 413 428
Deferred lease costs - FortisBC Electric 73 70
Rate stabilization accounts - electric
utilities 54 55
Rate stabilization accounts - FortisBC Energy
companies 53 105
Replacement energy deferral - Point Lepreau
(1) 47 47
Deferred energy management costs 42 36
Deferred operating overhead costs 27 22
Customer Care Enhancement Project cost
deferral 25 13
Income taxes recoverable on other post-
employment benefit ("OPEB") plans 23 22
Deferred net losses on disposal of utility
capital assets 22 23
Whistler pipeline contribution deferral 16 16
Pension cost variance deferral 13 10
Alternative energy projects cost deferral 11 8
Deferred development costs for capital 10 11
Deferred costs - smart meters 8 8
Alberta Electric System Operator ("AESO")
charges deferral - 44
Other regulatory assets 78 71
----------------------------------------------------------------------------
Total regulatory assets 1,579 1,619
Less: current portion (122) (219)
----------------------------------------------------------------------------
Long-term regulatory assets 1,457 1,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) New Brunswick Power Point Lepreau Nuclear Generating Station
As at
June 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Regulatory liabilities
Non-ARO removal cost provision 370 354
Rate stabilization accounts - FortisBC Energy
companies 187 127
Rate stabilization accounts - electric utilities 40 33
AESO charges deferral 22 12
Deferred income taxes 16 9
Deferred interest 9 10
Income tax variance deferral 8 12
Performance-based rate-setting incentive
liabilities 8 7
Southern Crossing Pipeline deferral 6 8
Unrecognized net gains on disposal of utility
capital assets - 6
Other regulatory liabilities 24 20
----------------------------------------------------------------------------
Total regulatory liabilities 690 598
Less: current portion (82) (43)
----------------------------------------------------------------------------
Long-term regulatory liabilities 608 555
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended Year-to-Date
June 30, 2012 June 30, 2012
Number of Number of
Shares Amount Shares Amount
(in thousands) ($ millions) (in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning
of period 189,274 3,050 188,828 3,036
Dividend
Reinvestment
Plan 495 15 895 28
Consumer Share
Purchase Plan 11 1 24 1
Stock Option
Plans 187 5 220 6
----------------------------------------------------------------------------
Balance, end of
period 189,967 3,071 189,967 3,071
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subscription Receipts Offering
In June 2012, to finance a portion of the pending acquisition of CH Energy
Group, Fortis sold 18,500,000 Subscription Receipts at $32.50 each through a
bought-deal offering underwritten by a syndicate of underwriters led by CIBC
World Markets Inc., Scotia Capital Inc. and TD Securities Inc. (collectively the
"Underwriters"), resulting in gross proceeds of approximately $601 million. The
gross proceeds from the sale of the Subscription Receipts are being held by an
escrow agent, pending receipt of all required approvals and satisfaction of
closing conditions included in the agreement to acquire CH Energy Group (the
"Release Conditions"). The Subscription Receipts began trading on the Toronto
Stock Exchange on June 27, 2012 under the symbol "FTS.R".
Each Subscription Receipt will entitle the holder thereof to receive, on
satisfaction of the Release Conditions and without payment of additional
consideration, one common share of Fortis and a cash payment equal to the
dividends declared on Fortis common shares to holders of record during the
period from June 27, 2012 to the date of issuance of the common shares in
respect of the Subscription Receipts.
If the Release Conditions are not satisfied by June 30, 2013, or if the share
purchase agreement relating to the acquisition of CH Energy Group is terminated
prior to such time, holders of Subscription Receipts shall be entitled to
receive from the escrow agent an amount equal to the full subscription price
thereof plus their pro rata share of the interest earned on such amount (Note
18).
5. NON-CONTROLLING INTERESTS
As at
June 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Waneta Expansion Limited Partnership ("Waneta
Partnership") 184 128
Caribbean Utilities 72 73
Mount Hayes Limited Partnership (Note 18) 12 -
Preference shares of Newfoundland Power 7 7
----------------------------------------------------------------------------
275 208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $32.40 per
PSU, for a total of approximately $1.5 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.
In May 2012 62,000 PSUs were granted to the President and CEO of the
Corporation. Each PSU represents a unit with an underlying value equivalent to
the value of one common share of the Corporation. The maturation period of the
May 2012 PSU grant is three years, at which time a cash payment may be made to
the President and CEO after evaluation by the Human Resources Committee of the
Board of Directors of the achievement of payment requirements.
In May 2012 the 2012 Stock Option Plan ("2012 Plan") was approved at the Annual
General Meeting of the Corporation's shareholders. The 2012 Plan will ultimately
replace the 2002 Stock Option Plan ("2002 Plan") and the 2006 Stock Option Plan
("2006 Plan"). The 2002 Plan and 2006 Plan will cease to exist when all
outstanding options are exercised or expire in or before 2016 and 2018,
respectively. The Corporation has ceased to grant options under the 2002 Plan
and 2006 Plan and all new options granted after 2011 will be made under the 2012
Plan.
In May 2012 the Corporation granted 789,220 options to purchase common shares
under its 2012 Plan at the five-day volume weighted average trading price
immediately preceding the date of grant of $34.27. The options vest evenly over
a four-year period on each anniversary of the date of grant. The options expire
10 years after the date of grant. The fair value of each option granted was
$4.21 per option.
The fair value was estimated at the date of grant using the Black-Scholes fair
value option-pricing model and the following assumptions:
Dividend yield (%) 3.67
Expected volatility (%) 22.2
Risk free interest rate (%) 1.50
Weighted average expected life (years) 5.3
For the three and six months ended June 30, 2012, stock-based compensation
expense of approximately $1.5 million and $3 million, respectively, was
recognized ($1.5 million and $3 million for the three and six months ended June
30, 2011, respectively).
7. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of
defined benefit pension plans and defined contribution pension plans, including
group registered retirement savings plans, for employees. The Corporation and
certain subsidiaries also offer OPEB plans for qualifying employees. The net
benefit cost of providing the defined benefit pension and OPEB plans is detailed
in the following tables.
Quarter Ended June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Components of net
benefit cost:
Service costs 7 5 1 1
Interest costs 11 12 3 3
Expected return on plan
assets (13) (12) - -
Amortization of
actuarial losses 7 5 1 1
Amortization of past
service costs/plan
amendments - - (1) (1)
Amortization of
transitional obligation 1 - 1 -
Regulatory adjustments (5) (2) - 1
----------------------------------------------------------------------------
Net benefit cost 8 8 5 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date June 30
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Components of net
benefit cost:
Service costs 14 10 3 2
Interest costs 23 24 6 6
Expected return on plan
assets (25) (24) - -
Amortization of
actuarial losses 13 10 2 2
Amortization of past
service costs/plan
amendments - - (2) (2)
Amortization of
transitional obligation 1 - 1 -
Regulatory adjustments (6) (4) 1 2
----------------------------------------------------------------------------
Net benefit cost 20 16 11 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three and six months ended June 30, 2012, the Corporation expensed $3
million and $7 million, respectively ($4 million and $8 million for the three
and six months ended June 30, 2011, respectively) related to defined
contribution pension plans.
8. OTHER INCOME (EXPENSES), NET
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Net foreign exchange gain 2 - - -
Equity component of
allowance for funds used
during construction 1 3 3 8
Interest income 1 1 2 2
Acquisition-related
expenses (4) - (8) -
Other income, net of
expenses - - - 2
----------------------------------------------------------------------------
- 4 (3) 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The net foreign exchange gain for the three and six months ended June 30, 2012
includes approximately $2 million and $0.5 million, respectively, related to the
translation into Canadian dollars of the Corporation's long-term other asset
associated with Belize Electricity (Notes 17 and 19).
The acquisition-related expenses are associated with the pending acquisition of
CH Energy Group (Notes 1 and 18).
9. FINANCE CHARGES
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Interest:
Long-term debt and
finance and capital
lease obligations 93 91 187 184
Short-term borrowings
and other finance
charges 2 5 3 9
Debt component of
allowance for funds
used during
construction (3) (3) (7) (8)
----------------------------------------------------------------------------
92 93 183 185
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 income taxes to consolidated effective income taxes.
Quarter Ended Year-to-Date
June 30 June 30
($ millions, except as
noted) 2012 2011 2012 2011
----------------------------------------------------------------------------
Combined Canadian
federal and provincial
statutory income tax
rate 29.0% 30.5% 29.0% 30.5%
----------------------------------------------------------------------------
Statutory income tax
rate applied to
earnings before income
taxes 26 27 72 75
Difference between
Canadian statutory
income tax rate and
rates applicable to
foreign subsidiaries (5) (3) (7) (5)
Difference in Canadian
provincial statutory
income tax rates
applicable to
subsidiaries in
different Canadian
jurisdictions (3) (3) (8) (8)
Items capitalized for
accounting purposes but
expensed for income tax
purposes (9) (12) (28) (28)
Difference between
capital cost allowance
and amounts claimed for
accounting purposes 1 4 4 6
Non-deductible expenses 2 - 3 1
Difference between
enacted and
substantially enacted
income tax rates
associated with Part
VI.1 tax 3 1 3 2
Difference between
employee future
benefits paid and
amounts expensed for
accounting purposes 1 - 1 -
Other (2) 2 (3) 4
----------------------------------------------------------------------------
Income taxes 14 16 37 47
----------------------------------------------------------------------------
Effective income tax
rate 15.4% 18.2% 15.0% 19.0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2012, the Corporation had approximately $85 million (December 31,
2011 - $86 million) in non-capital and capital loss carryforwards, of which $13
million (December 31, 2011 - $13 million) has not been recognized in the
consolidated financial statements. The non-capital loss carryforwards expire
between 2014 and 2032.
11. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted
average number of common shares outstanding. Diluted EPS is calculated using the
treasury stock method for options and the "if-converted" method for convertible
securities.
EPS were as follows:
Quarter Ended June 30
2012 2011
---------------------------------------------------------------
Earnings Weighted Earnings Weighted
to Common Average to Common Average
Shareholders Shares Shareholders Shares
(in (in
($ millions) millions) EPS ($ millions) millions) EPS
----------------------------------------------------------------------------
Basic EPS 62 189.6 $ 0.33 57 177.1 $ 0.32
Effect of
potential
dilutive
securities:
Stock
Options - 0.9 - 1.2
Preference
Shares 4 10.3 4 10.1
Convertible
Debentures - - 1 1.4
----------------------------------------------------------------------------
66 200.8 62 189.8
Deduct anti-
dilutive
impacts:
Preference
Shares (4) (10.3) (4) (10.1)
Convertible
Debentures - - (1) (1.4)
----------------------------------------------------------------------------
Diluted EPS 62 190.5 $ 0.33 57 178.3 $ 0.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date June 30
2012 2011
-----------------------------------------------------------
Earnings Weighted Earnings Weighted
to Common Average to Common Average
Shareholders Shares Shareholders Shares
(in (in
($ millions) millions) EPS ($ millions) millions) EPS
----------------------------------------------------------------------------
Basic EPS 183 189.3 $ 0.97 173 175.8 $ 0.98
Effect of
potential
dilutive
securities:
Stock Options - 0.9 - 1.2
Preference
Shares 8 10.3 8 10.1
Convertible
Debentures - - 1 1.4
----------------------------------------------------------------------------
Diluted EPS 191 200.5 $ 0.95 182 188.5 $ 0.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. BUSINESS ACQUISITION
In April 2012 FortisOntario exercised its option, under the terms of a 10-year
operating lease agreement with the City of Port Colborne (the "City") that
commenced in April 2002, to purchase the remaining assets of Port Colborne Hydro
for approximately $7 million. Under the lease arrangement with the City, and now
through ownership of the previously leased assets, FortisOntario operates and
maintains the City's electricity distribution system for provision of
electricity service to the residents of Port Colborne. Throughout the 10-year
lease term, FortisOntario incurred approximately $17 million in capital
expenditures in Port Colborne Hydro's electricity distribution system. The
exercise of the purchase option, which qualifies as a business combination,
provides ownership and legal title to all of the assets, including equipment,
real property and distribution assets, which constitutes the entire distribution
system in Port Colborne. The purchase was approved by the Ontario Energy Board.
FortisOntario is regulated under traditional cost of service and the
determination of revenue and earnings is based on a regulated rate of return
that is applied to historic values which do not change with a change of
ownership. Therefore, fair market value approximates book value and no
adjustments were recorded for the assets acquired, because all of the economic
benefits and obligations associated with them beyond regulated rates of return
accrue to the customers. Accordingly, $3 million of the purchase price was
allocated to utility capital assets and $4 million was recognized as goodwill in
the preliminary purchase price allocation.
13. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
FortisBC
Quarter Ended Energy Total
Companies Newfound-
June 30, 2012 - Fortis FortisBC land Other Electric Electric
Carib-
($ millions) Canadian Alberta Electric Power Canadian Canadian bean
----------------------------------------------------------------------------
Revenue 264 110 67 130 82 389 67
Energy supply
costs 109 - 13 78 51 142 39
Operating
expenses 63 37 21 17 12 87 9
Depreciation
and
amortization 40 30 12 11 6 59 9
----------------------------------------------------------------------------
Operating
income 52 43 21 24 13 101 10
Other income
(expenses),
net 1 - - 1 - 1 1
Finance
charges 36 17 10 9 6 42 3
Income tax
expense
(recovery) 3 - 2 4 2 8 -
----------------------------------------------------------------------------
Net earnings
(loss) 14 26 9 12 5 52 8
Non-
controlling
interests 1 - - - - - 2
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 13 26 9 12 5 52 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 67 515 142
Identifiable
assets 4,605 2,543 1,671 1,251 692 6,157 737
----------------------------------------------------------------------------
Total assets 5,518 2,770 1,892 1,251 759 6,672 879
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 32 121 16 21 13 171 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Quarter Ended
June 30, 2011
($ millions)
----------------------------------------------------------------------------
Revenue 319 103 65 133 78 379 85
Energy supply
costs 170 - 11 80 47 138 53
Operating
expenses 70 36 21 17 11 85 11
Depreciation
and
amortization 27 33 12 11 6 62 8
----------------------------------------------------------------------------
Operating
income 52 34 21 25 14 94 13
Other income
(expenses),
net 3 - - - - - 1
Finance
charges 36 16 9 9 6 40 4
Income tax
expense
(recovery) 4 - 3 6 2 11 1
----------------------------------------------------------------------------
Net earnings
(loss) 15 18 9 10 6 43 9
Non-
controlling
interests - - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 15 18 9 10 6 43 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 132
Identifiable
assets 4,380 2,244 1,613 1,233 661 5,751 673
----------------------------------------------------------------------------
Total assets 5,293 2,471 1,834 1,233 724 6,262 805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 65 86 23 17 11 137 19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------------
Quarter Ended Inter-
June 30, 2012 Fortis Fortis Corporate segment
($ millions) Generation Properties and Other eliminations Consolidated
---------------------------------------------------------------------------
Revenue 9 64 7 (8) 792
Energy supply
costs 1 - - - 291
Operating
expenses 1 42 3 (1) 204
Depreciation
and
amortization 1 5 - - 114
---------------------------------------------------------------------------
Operating
income 6 17 4 (7) 183
Other income
(expenses),
net - - (3) - -
Finance
charges - 6 12 (7) 92
Income tax
expense
(recovery) 1 3 (1) - 14
---------------------------------------------------------------------------
Net earnings
(loss) 5 8 (10) - 77
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 12 - 12
---------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 8 (22) - 62
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,570
Identifiable
assets 653 620 501 (412) 12,861
---------------------------------------------------------------------------
Total assets 653 620 501 (412) 14,431
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(1) 57 10 - - 282
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Quarter Ended
June 30, 2011
($ millions)
---------------------------------------------------------------------------
Revenue 7 60 7 (11) 846
Energy supply
costs 1 - - (4) 358
Operating
expenses 1 40 3 (1) 209
Depreciation
and
amortization 1 4 - - 102
---------------------------------------------------------------------------
Operating
income 4 16 4 (6) 177
Other income
(expenses),
net - - - - 4
Finance
charges 1 6 12 (6) 93
Income tax
expense
(recovery) 1 2 (3) - 16
---------------------------------------------------------------------------
Net earnings
(loss) 2 8 (5) - 72
Non-
controlling
interests - - - - 3
Preference
share
dividends - - 12 - 12
---------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 2 8 (17) - 57
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Goodwill - - - - 1,556
Identifiable
assets 473 581 675 (422) 12,111
---------------------------------------------------------------------------
Total assets 473 581 675 (422) 13,667
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Gross capital
expenditures
(1) 59 6 - - 286
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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.
REGULATED
---------------------------------------------------------------
Gas
Utilities Electric Utilities
---------------------------------------------------------------
FortisBC
Year-to-Date Energy Total
Companies Newfound-
June 30, 2012 - Fortis FortisBC land Other Electric Electric
Carib-
($ millions) Canadian Alberta Electric Power Canadian Canadian bean
----------------------------------------------------------------------------
Revenue 812 218 154 322 173 867 130
Energy supply
costs 411 - 38 220 109 367 79
Operating
expenses 133 76 42 37 24 179 17
Depreciation
and
amortization 80 65 24 22 13 124 16
----------------------------------------------------------------------------
Operating
income 188 77 50 43 27 197 18
Other income
(expenses),
net 1 2 - 1 - 3 1
Finance
charges 71 32 20 18 11 81 7
Income tax
expense
(recovery) 22 - 5 7 4 16 -
----------------------------------------------------------------------------
Net earnings
(loss) 96 47 25 19 12 103 12
Non-
controlling
interests 1 - - - - - 3
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 95 47 25 19 12 103 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 67 515 142
Identifiable
assets 4,605 2,543 1,671 1,251 692 6,157 737
----------------------------------------------------------------------------
Total assets 5,518 2,770 1,892 1,251 759 6,672 879
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 78 200 33 36 22 291 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2011
($ millions)
----------------------------------------------------------------------------
Revenue 893 203 148 316 169 836 160
Energy supply
costs 514 - 34 214 107 355 99
Operating
expenses 144 71 39 37 23 170 22
Depreciation
and
amortization 54 66 23 21 12 122 17
----------------------------------------------------------------------------
Operating
income 181 66 52 44 27 189 22
Other income
(expenses),
net 6 3 1 - - 4 2
Finance
charges 70 29 19 18 11 77 9
Income tax
expense
(recovery) 27 1 6 10 4 21 1
----------------------------------------------------------------------------
Net earnings
(loss) 90 39 28 16 12 95 14
Non-
controlling
interests - - - - - - 4
Preference
share
dividends - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 90 39 28 16 12 95 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill 913 227 221 - 63 511 132
Identifiable
assets 4,380 2,244 1,613 1,233 661 5,751 673
----------------------------------------------------------------------------
Total assets 5,293 2,471 1,834 1,233 724 6,262 805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 113 171 53 31 19 274 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NON-REGULATED
------------------------------------
Year-to-Date Inter-
June 30, 2012 Fortis Fortis Corporate segment
($ millions) Generation Properties and Other eliminations Consolidated
----------------------------------------------------------------------------
Revenue 18 116 13 (15) 1,941
Energy supply
costs 1 - - (1) 857
Operating
expenses 4 82 6 (3) 418
Depreciation
and
amortization 2 10 1 - 233
----------------------------------------------------------------------------
Operating
income 11 24 6 (11) 433
Other income
(expenses),
net 1 - (8) (1) (3)
Finance
charges 1 12 23 (12) 183
Income tax
expense
(recovery) 1 3 (5) - 37
----------------------------------------------------------------------------
Net earnings
(loss) 10 9 (20) - 210
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 23 - 23
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 10 9 (43) - 183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,570
Identifiable
assets 653 620 501 (412) 12,861
----------------------------------------------------------------------------
Total assets 653 620 501 (412) 14,431
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 105 15 - - 511
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year-to-Date
June 30, 2011
($ millions)
----------------------------------------------------------------------------
Revenue 14 110 13 (21) 2,005
Energy supply
costs 1 - - (8) 961
Operating
expenses 4 77 5 (3) 419
Depreciation
and
amortization 2 9 1 - 205
----------------------------------------------------------------------------
Operating
income 7 24 7 (10) 420
Other income
(expenses),
net 1 - - (1) 12
Finance
charges 2 12 26 (11) 185
Income tax
expense
(recovery) 1 3 (6) - 47
----------------------------------------------------------------------------
Net earnings
(loss) 5 9 (13) - 200
Non-
controlling
interests - - - - 4
Preference
share
dividends - - 23 - 23
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 9 (36) - 173
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill - - - - 1,556
Identifiable
assets 473 581 675 (422) 12,111
----------------------------------------------------------------------------
Total assets 473 581 675 (422) 13,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital
expenditures
(1) 82 9 - - 518
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 and six months ended June 30, 2012 and 2011 were as
follows:
Significant Inter-Segment
Transactions Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Sales from Fortis Generation to
Regulated Electric Utilities -
Caribbean - 3 - 7
Sales from Fortis Generation to
Other Canadian Electric Utilities - 1 - 1
Sales from Newfoundland Power to
Fortis Properties 1 1 3 2
Inter-segment finance charges on
lending from:
Fortis Generation to Other
Canadian Electric Utilities 1 1 1 1
Corporate to Regulated Electric
Utilities - Canadian - 1 - 1
Corporate to Regulated Electric
Utilities - Caribbean 1 1 2 2
Corporate to Fortis Generation 1 - 1 1
Corporate to Fortis Properties 4 3 8 6
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The significant inter-segment asset balances were as follows:
As at June 30
($ 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 77 68
Corporate to Fortis Generation 14 33
Corporate to Fortis Properties 281 225
Other inter-segment assets 20 26
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Total inter-segment eliminations 412 422
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14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended Year-to-Date
June 30 June 30
($ millions) 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash paid for:
Interest 105 100 185 181
Income taxes 18 21 51 45
Change in non-cash operating
working capital:
Accounts receivable 187 105 128 69
Prepaid expenses (8) (6) (6) (7)
Inventories (31) (24) 27 56
Regulatory assets - current
portion 5 (1) 48 (6)
Accounts payable and other
current liabilities (76) (31) (67) (38)
Regulatory liabilities -
current portion 6 6 32 32
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83 49 162 106
------------------------------------------------
------------------------------------------------
Non-cash investing and
financing activities:
Common share dividends
reinvested 15 15 28 31
Exercise of stock options
into common shares 1 1 1 2
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15. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Corporation generally limits the use of derivative instruments to those that
qualify as accounting or economic hedges. As at June 30, 2012, the Corporation's
derivative contracts consisted of fuel option contracts, natural gas swap and
option contracts, and gas purchase contract premiums. The fuel option contracts
are held by Caribbean Utilities and the remaining derivative instruments are
held by the FortisBC Energy companies.
Volume of Derivative Activity
As at June 30, 2012, the following notional volumes related to fuel option
contracts and natural gas derivatives that are expected to be settled are
outlined below.
2012 2013 2014
----------------------------------------------------------------------------
Fuel option contracts (millions of gallons) 3 1 -
Swaps and options (petajoules) 14 18 7
Gas purchase contract premiums (petajoules) 67 19 5
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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
June 30, December 31,
($ millions) 2012 2011
----------------------------------------------------------------------------
Gross derivatives balance (1) 91 136
Netting (2) - -
Cash collateral - -
----------------------------------------------------------------------------
Total derivative balances (3) 91 136
--------------------------
--------------------------
(1) Refer to Note 16 for a discussion of the valuation techniques used to
calculate the fair value of the derivative instruments.
(2) Positions, by counterparty, are netted where the intent and legal right
to offset exists.
(3) Unrealized losses of $91 million on commodity risk-related derivative
instruments were recognized as current regulatory assets as at June 30,
2012 (December 31, 2011 - $136 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 and 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.
16. 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 point-in-time estimates based on current and relevant
market information about the instruments as at the balance sheet dates. The
estimates cannot be determined with precision as they involve uncertainties and
matters of judgment and, therefore, may not be relevant in predicting the
Corporation's future consolidated earnings or cash flows.
The following table details the estimated fair value measurements of the
Corporation's financial instruments, all of which were measured using Level 2
inputs except for certain long-term debt as noted.
As at
Asset (Liability) June 30, 2012 December 31, 2011
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
Other asset - Belize
Electricity (1) 106 - (2) 106 - (2)
Long-term debt, including
current portion (3) (5,968) (7,394) (5,788) (7,172)
Waneta Partnership
promissory note (4) (46) (50) (45) (49)
Foreign exchange forward
contract (5) - - - -
Fuel option contracts (5) (1) (1) (1) (1)
Natural gas derivatives: (5)
Swaps and options (93) (93) (135) (135)
Gas purchase contract
premiums 3 3 - -
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----------------------------------------------------------------------------
(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) The Corporation's $200 million unsecured debentures due 2039 and
consolidated credit facilities classified as long-term are valued using
Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
(4) Included in long-term other liabilities on the consolidated balance
sheet
(5) The fair values of the derivatives were recorded in accounts payable and
other current liabilities as at June 30, 2012 and December 31, 2011. As
at December 31, 2011, the fair value of the foreign exchange forward
contract was less than $1 million and the contract expired in April
2012.
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 fuel option contracts are used by Caribbean Utilities to reduce the impact
of volatility in fuel prices on customer rates, as approved by the regulator
under the Company's Fuel Price Volatility Management Program. The fair value of
the fuel option contracts reflects only the value of the heating oil derivative
and not the offsetting change in the value of the underlying future purchases of
heating oil and is calculated using published market prices for heating oil. The
fuel option contracts mature in March 2013.
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. 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 fuel option contracts and natural gas derivatives were
estimates of the amounts that the utilities would have to receive or pay to
terminate the outstanding contracts as at the balance sheet dates. As at June
30, 2012, none of the fuel option contracts or natural gas derivatives were
designated as hedges of fuel purchases or natural gas supply contracts. However,
any gains or losses associated with changes in the fair value of the derivatives
were deferred as a regulatory asset or liability for recovery from, or refund
to, customers in future rates, as permitted by the regulators.
17. 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 June 30,
2012, the utility's gross credit risk exposure was approximately $160 million,
representing the projected value of retailer billings over a 60-day period. The
Company has reduced its exposure to approximately $8 million by obtaining from
the retailers either a cash deposit, bond, letter of credit or an
investment-grade credit rating from a major rating agency, or by having the
retailer obtain a financial guarantee from an entity with an investment-grade
credit rating.
The FortisBC Energy companies are exposed to credit risk in the event of
non-performance by counterparties to derivative financial instruments. To help
mitigate credit risk, the FortisBC Energy companies deal with high
credit-quality institutions in accordance with established credit-approval
practices. The counterparties with which the FortisBC Energy companies have
significant transactions are A-rated entities or better. The Company uses
netting arrangements to reduce credit risk and net settles payments with
counterparties where net settlement provisions exist.
The following table summarizes the FortisBC Energy companies' net credit risk
exposure to its counterparties, as well as credit risk exposure to counter
parties accounting for greater than 10% net credit exposure.
As at
June 30, December 31,
($ millions, except for number of customers) 2012 2011
----------------------------------------------------------------------------
Gross credit exposure before credit collateral
(1) 93 136
Credit collateral - -
----------------------------------------------------------------------------
Net credit exposure (2) 93 136
----------------------------------------------------------------------------
Number of counterparties greater than 10% 4 4
Net exposure to counterparties greater than 10% 73 104
----------------------------------------------------------------------------
(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 $106
million, including foreign exchange impacts, recognized on the consolidated
balance sheet related to its expropriated investment in Belize Electricity (Note
19).
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 June 30, 2012, average annual
consolidated long-term debt maturities and repayments over the next five years
are expected to be approximately $295 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 June 30, 2012, the Corporation and its subsidiaries had consolidated
credit facilities of approximately $2.5 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.
Approximately $2.3 billion of the total credit facilities are committed credit
facilities with maturities ranging from 2013 to 2017.
The following table outlines the credit facilities of the Corporation and its
subsidiaries.
As at
December
Regulated Fortis Corporate June 30, 31,
($ millions) Utilities Properties and Other 2012 2011
----------------------------------------------------------------------------
Total credit
facilities 1,434 13 1,045 2,492 2,248
Credit facilities
utilized:
Short-term
borrowings (1) (76) (5) - (81) (159)
Long-term debt (2) (123) - (185) (308) (74)
Letters of credit
outstanding (67) - (1) (68) (66)
----------------------------------------------------------------------------
Credit facilities
unused 1,168 8 859 2,035 1,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The weighted average interest rate on short-term borrowings was
approximately 2.1% as at June 30, 2012 (December 31, 2011 - 1.9%).
(2) As at June 30, 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 2.3% as at June 30, 2012
(December 31, 2011 - 2.6%).
As at June 30, 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 revolving 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.
In May 2012 FHI extended its $30 million operating credit facility to mature in
May 2013 from May 2012. The new agreement contains substantially similar terms
and conditions as the previous credit facility agreement.
In May 2012 Fortis increased the amount available for borrowing under its
committed revolving corporate credit facility from $800 million to $1 billion,
as permitted under the credit facility agreement.
In May 2012 Caribbean Utilities renegotiated and increased the amount available
for borrowing under its unsecured credit facilities to US$47 million from US$33
million.
In June 2012 FortisOntario entered into a new short-term credit facility
agreement for $30 million replacing two short-term credit facilities totaling
$20 million. The new credit facility agreement reflects a decrease in pricing
and improved terms and conditions. In July 2012 the former credit facilities
were terminated.
In July 2012 FEI entered into a one-year extension of its $500 million unsecured
committed revolving credit facility agreement, amending the maturity date from
August 2013 to August 2014. The amended agreement reflects an increase in
pricing but, otherwise, contains substantially similar terms and conditions as
the previous credit facility agreement.
In July 2012 FortisAlberta renegotiated and amended its $250 million unsecured
committed revolving credit facility, obtaining an extension to the maturity of
the facility to August 2016 from September 2015 and a decrease in pricing. The
amended credit facility agreement otherwise contains substantially similar terms
and conditions as the previous credit facility agreement.
The Corporation and its currently rated utilities target investment-grade credit
ratings to maintain capital market access at reasonable interest rates. As at
June 30, 2012, the Corporation's credit ratings were as follows:
Standard & Poor's ("S&P") A- (long-term corporate and unsecured debt credit
rating)
DBRS A (low) (unsecured debt credit rating)
In May 2012 and July 2012, S&P and DBRS, respectively, affirmed the
Corporation's debt credit ratings. Also, S&P and DBRS removed the ratings from
credit watch with negative implications and under review with developing
implications, respectively, where the ratings had been placed in February 2012,
mainly reflecting the Corporation's financing plans for the pending acquisition
of CH Energy Group and the expected completion of the Waneta Expansion on time
and on budget.
The above-noted 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.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investment in, foreign subsidiaries are
exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The
Corporation has effectively decreased the above-noted exposure through the use
of US dollar 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 Belize Electric Company Limited is the US dollar. Belize
Electricity's financial results were denominated in Belizean dollars, which are
pegged to the US dollar.
As at June 30, 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 June 30,
2012, the Corporation had approximately US$13 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 gains and losses are also recorded in other comprehensive
income.
Effective June 20, 2011, the Corporation's asset associated with its 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 net
foreign exchange gain in earnings of approximately $2 million and $0.5 million
during the three and six months ended June 30, 2012, respectively (Note 8).
FEI's US dollar payments under a contract for the implementation of a customer
care information system were exposed to fluctuations in the US
dollar-to-Canadian dollar exchange rate. FEI had entered into a foreign exchange
forward contract to hedge this exposure. FEI had 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. FEI's
foreign exchange forward contract expired in April 2012.
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, to mitigate
gas price volatility on customer rates and to 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 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.
18. 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.
(a) Pending Acquisition
In February 2012 Fortis entered into an agreement to acquire CH Energy Group for
US$1.5 billion, including the assumption of approximately US$500 million in debt
on closing. The transaction received CH Energy Group shareholder approval in
June 2012 and regulatory approval from FERC and the Committee on Foreign
Investment in the United States in July 2012. The acquisition is subject to
certain other approvals, including approval by the NYSPSC, and satisfaction of
customary closing conditions. The NYSPSC is currently reviewing the application
for approval of the transaction jointly filed by Fortis and CH Energy Group in
April 2012 (Note 1).
(b) Subscription Receipts Offering
To finance a portion of the purchase price of CH Energy Group, Fortis sold
18,500,000 Subscription Receipts in June 2012 resulting in gross proceeds of
approximately $601 million. Each Subscription Receipt entitles the holder to
receive, on satisfaction of Release Conditions, and without payment of
additional consideration, one common share of Fortis and a cash payment equal to
the dividends declared on Fortis common shares to holders of record during the
period from June 27, 2012 to the date of issuance of the common shares in
respect of the Subscription Receipts. In the event that the Release Conditions
are not satisfied by June 30, 2013, or if the share purchase agreement relating
to the acquisition is terminated prior to such time, the holders of Subscription
Receipts will be entitled to receive an amount equal to the full subscription
price thereof plus their pro rata share of the interest earned on such amount
(Note 4).
(c) Other
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 million,
including interest, over five years beginning in 2012. The Company fulfilled its
2012 annual solvency deficit funding requirement during the second quarter of
2012. The increase in funding contributions is expected to be recovered from
customers in future rates.
19. 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 discontinued the
consolidation method of accounting for Belize Electricity, effective June 20,
2011, and classified the book value of the previous investment in the utility as
a long-term other asset on the consolidated balance sheet.
In October 2011 Fortis commenced an action in the Belize Supreme Court with
respect to 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
pursuing alternative options for obtaining fair compensation from the GOB.
Exploits River Hydro Partnership
The Exploits River Hydro Partnership ("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.
20. CONTINGENT LIABILITIES
The Corporation and its subsidiaries are subject to various legal proceedings
and claims associated with the ordinary course of business operations.
Management believes that the amount of liability, if any, from these actions
would not have a material effect on the Corporation's consolidated financial
position or results of operations.
The following describes the nature of the Corporation's contingent liabilities.
Fortis
In May 2012 CH Energy Group and Fortis entered into a proposed settlement
agreement with counsel to plaintiff shareholders pertaining to several
complaints, which named Fortis and other defendants, which were filed in, or
transferred to, the Supreme Court of the State of New York, County of New York,
relating to the proposed acquisition of CH Energy Group by Fortis. The
complaints generally alleged that the directors of CH Energy Group breached
their fiduciary duties in connection with the proposed acquisition and that CH
Energy Group, Fortis, FortisUS Inc. and Cascade Acquisition Sub Inc. aided and
abetted that breach. The settlement agreement is subject to court approval.
FHI
During 2007 and 2008, a non-regulated subsidiary of FHI received Notices of
Assessment from Canada Revenue Agency 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. Following a mediation, in which FHI did not
participate, FHI was advised that all matters have now been settled.
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. A date for mediation of this matter has been
set for December 2012. The outcome cannot be reasonably determined and estimated
at this time and, accordingly, no amount has been accrued in the consolidated
financial statements.
The Government of British Columbia filed a claim in the British Columbia Supreme
Court in June 2012 claiming on its behalf, and on behalf of approximately 17
homeowners, damages suffered as a result of a landslide caused by a dam failure
in Oliver, British Columbia in 2010. The Government of British Columbia alleges
in its claim that the dam failure was caused by the defendants', which includes
FortisBC Electric, use of a road on top of the dam. The Government of British
Columbia estimates its damages and the damages of the homeowners, on whose
behalf it is claiming, to be approximately $12 million. FortisBC Electric has
not been served, however, has retained counsel and has contacted its insurers.
The outcome cannot be reasonably determined and estimated at this time and,
accordingly, no amount has been accrued in the consolidated financial
statements.
21. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period
presentation. The most significant change related to a decrease in current and
long-term debt of $4 million and $120 million, respectively, and a corresponding
increase in current and long-term capital lease and finance obligations
associated with a change in the presentation of finance obligations.
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 Upstate New York. 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;
First Preference Shares, Series H; and Subscription Receipts 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, FTS.PR.H and FTS.R, 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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