Fortis Earns $45 Million in Third Quarter

Fortis Earns $45 Million in Third Quarter 
ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwire) -- 11/01/12 --
Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved third
quarter net earnings attributable to common equity shareholders of
$45 million, or $0.24 per common share, compared to $56 million, or
$0.30 per common share, for the third quarter of 2011. Year-to-date
net earnings attributable to common equity shareholders were $228
million, or $1.20 per common share, compared to $229 million, or
$1.28 per common share, for the same period last year.  
In 2012 earnings for the third quarter and year to date were reduced
by $3.5 million and $10 million, respectively, related to foreign
exchange and CH Energy Group, Inc. ("CH Energy Group")
acquisition-related expenses. In 2011 earnings for the third quarter
and year to date were favourably impacted by a one-time $11 million
after-tax merger termination fee paid to Fortis and $2.5 million of
foreign exchange. 
Excluding the above impacts, improved performance at the western
Canadian regulated electric utilities for the quarter was partially
offset by decreased non-regulated hydroelectric generation and a
higher loss incurred at the regulated gas utilities. 
Canadian Regulated Electric Utilities, led by FortisAlberta and
FortisBC Electric, contributed earnings of $54 million, up $11
million from the third quarter of 2011. At FortisAlberta, higher net
transmission revenue, growth in energy infrastructure investment and
timing of operating expenses during 2012 were partially offset by a
lower allowed rate of return on common shareholder's equity. At
FortisBC Electric, performance was driven by growth in energy
infrastructure investment, higher pole-attachment revenue and
lower-than-expected finance charges.  
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets for approximately $55 million. FortisBC
Electric has operated and maintained the City of Kelowna's electrical
utility assets, which currently serve approximately 15,000 customers,
since 2000. Closing of the transaction is subject to certain
conditions and receipt of certain approvals, including regulatory
approval. FortisBC Electric and the City of Kelowna are working
towards closing the transaction by the end of the first quarter of
2013.  
Canadian Regulated Gas Utilities incurred a loss of $6 million
compared to a loss of $4 million for the third quarter of 2011. The
third quarter is normally a period of lower customer demand due to
warmer temperatures. The higher loss largely related to the
unfavourable impact of the difference in the timing of recognition of
revenue associated with seasonal gas consumption and certain
increased regulator-approved expenses in 2012, lower capitalized
allowance for funds used during construction, and lower-than-expected
customer additions in 2012. The above items were partially offset by
higher gas transportation volumes to industrial customers and the
timing of certain operating and maintenance expenses during 2012.  
Year-to-date 2012, regulatory decisions have been received for: (i)
2012-2013 revenue requirements at the FortisBC Energy companies; (ii)
2012 distribution revenue requirements at FortisAlberta; and (iii)
2012-2013 revenue requirements at FortisBC Electric. The Alberta
Utilities Commission issued a generic decision in September 2012 on
its Performance-Based Regulation ("PBR") Initiative, outlining the
PBR framework applicable to distribution utilities in Alberta for a
five-year term commencing January 1, 2013. FortisAlberta will file
the required PBR-compliance application in November 2012. A Generic
Cost of Capital ("GCOC") Proceeding to finalize 2013 cost of capital
for distribution utilities in Alberta is expected to commence late
2012 or early 2013. In British Columbia, the GCOC Proceeding to
determine cost of capital, effective January 1, 2013, continues with
an oral hearing scheduled for December 2012. Newfoundland Power filed
a general rate application in September 2012 for 2013 customer rates
and cost of capital. 
Caribbean Regulated Electric Utilities contributed $7 million of
earnings, compared to $6 million for the third quarter of 2011.
Fortis Turks and Caicos acquired Turks and Caicos Utilities Limited
("TCU") in August 2012 for an aggregate purchase price of
approximately $13 million (US$13 million), inclusive of debt assumed.
TCU serves more than 2,000 customers on Grand Turk and Salt Cay with
a diesel-fired generating capacity of approximately 9 megawatts
("MW"). The utility currently operates pursuant to a 50-year licence
that expires in 2036. 
Non-Regulated Fortis Generation contributed $5 million to earnings
compared to $8 million for the same quarter last year. The decrease
mainly related to lower production in Belize due to lower rainfall. 
Fortis Properties delivered earnings of $8 million, compared to $9
million for the third quarter of 2011, reflecting lower occupancy at
hotel operations in Atlantic Canada and central Canada, partially
offset by earnings contribution from the Hilton Suites Winnipeg
Airport hotel, which was acquired in October 2011. In October 2012
Fortis Properties acquired the 126-room StationPark All Suite Hotel
in London, Ontario for approximately $13 million.  
Corporate and other expenses were $23 million compared to $6 million
for the third quarter of 2011. Excluding the $11 million after-tax
termination fee paid to Fortis in July 2011, corporate and other
expenses increased quarter over quarter, mainly as a result of a $3
million after-tax foreign exchange loss recognized in the third
quarter of 2012 compared to a $2.5 million after-tax net foreign
exchange gain recognized in the same quarter last year.
Acquisition-related expenses associated with the CH Energy Group
transaction were approximately $0.5 million after-tax for the third
quarter of 2012. 
Consolidated capital expenditures, before customer contributions,
were approximately $794 million year-to-date 2012. At FortisBC Gas,
the Customer Care Enhancement Project came into service at the
beginning of January 2012. Construction of the $900 million, 335-MW
Waneta Expansion hydroelectric generating facility ("Waneta
Expansion") in British Columbia continues on time and on budget.
Approximately $380 million in total has been spent on the Waneta
Expansion since construction began in late 2010.  
Cash flow from operating activities was $804 million year-to-date
2012, up $120 million from the same period last year, driven by
favourable changes in regulatory deferral accounts and receivables
and the collection of increased depreciation and amortization expense
in customer rates. 
Fortis announced in February 2012 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 waiting period under the Hart-Scott-Rodino Antitrust Improvements
Act of 1976 expired in October 2012, satisfying another condition
necessary for consummation of the transaction. The transaction
remains subject to approval by the New York State Public Service
Commission ("NYSPSC"). 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, including receipt of regulatory approvals,
contained in the agreement to acquire 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 October 2012 FortisAlberta raised $125 million 40-year 3.98%
unsecured debentures, largely in support of its capital expenditure
program. 
Fortis corporate debt is rated A- by Standard & Poor's and A(low) by
DBRS.  
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 third quarter of 2012 or 2011. 
"Our utilities are focused on completing their remaining capital
projects for 2012. Our capital expenditures for the year are expected
to reach $1.3 billion," says Stan Marshall, President and Chief
Executive Officer, Fortis Inc. "Over the five-year period to 2016,
our capital program is expected to total $5.5 billion; Central
Hudson's capital program from 2013 through 2016 will add a further
approximate $0.5 billion," he explains. 
"Our largest utilities are busy with significant regulatory
processes, including those related to the determination of 2013
allowed returns," says Marshall. 
"Also on the regulatory front, we are focused on closing the CH
Energy Group transaction by the end of the first quarter of 2013.
Approval of the transaction by the NYSPSC is the one remaining
significant regulatory matter," concludes Marshall. 


 
                 Interim Management Discussion and Analysis                 
           For the three and nine months ended September 30, 2012           
                           Dated November 1, 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
nine months ended September 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 throughout the
remainder of 2012; the expected timing of filing regulatory
applications and of receipt of regulatory decisions; the expected
timing of the closing of the acquisition of CH Energy Group, Inc.
("CH Energy Group") by Fortis and the expectation that the
acquisition will be immediately accretive to earnings per common
share, excluding acquisition-related expenses; an expected favourable
impact on the Corporation's earnings in future periods upon final
enactment of legislative changes to Part VI.1 taxes; the expectation
of greater risk under Performance-Based Regulation ("PBR") that
FortisAlberta's earnings may be negatively impacted; and the
expectation that FortisBC Electric and the City of Kelowna will work
towards closing the proposed acquisition of the City of Kelowna's
electrical utility assets by FortisBC Electric by the end of the
first quarter of 2013. 
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 approval from the New
York State Public Service Commission, absent material conditions
imposed, 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; the absence of significant
changes in government energy plans and environmental laws that may
materially negatively affect the operations and cash flows of the
Corporation and its subsidiaries; 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, including increased risk at
FortisAlberta associated with the adoption of PBR under a five-year
term commencing in 2013; 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; risk of
having to raise alternative capital to finance the acquisition of CH
Energy Group if the closing of the acquisition occurs subsequent to
June 30, 2013; 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 nine months ended September 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 September 30, 2012, the Corporation's
electricity distribution systems met a combined peak demand of
approximately 5,225 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 nine months ended September 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
was 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.  
SIGNIFICANT ITEMS 
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. In addition, the
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976 expired in October 2012, satisfying another condition
necessary for consummation of the transaction.  
The transaction remains subject to approval by the New York State
Public Service Commission ("NYSPSC") and satisfaction of customary
closing conditions. The application for approval of the transaction
by the NYSPSC was 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.  
During the third quarter and year-to-date 2012, the Corporation's
earnings were reduced by $0.5 million and $7.5 million, respectively,
associated with CH Energy Group after-tax acquisition-related
expenses. 
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., realizing gross
proceeds of approximately $601 million. The gross proceeds from the
sale of the Subscription Receipts are being held by an escrow agent,
pending satisfaction of closing conditions, including receipt of
regulatory approvals, 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 agreement and plan of merger 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. 
For further information on the pending acquisition and the related
Subscription Receipts offering, refer to the "Business Risk
Management" section of this MD&A. 
Receipt of Regulatory Decisions: Year-to-date 2012, regulatory
decisions have been received for 2012-2013 revenue requirements at
the FortisBC Energy companies, 2012 distribution revenue requirements
at FortisAlberta and, recently in August, for 2012-2013 revenue
requirements at FortisBC Electric. The Alberta Utilities Commission
("AUC") issued a generic decision in September 2012 on its
Performance-Based Regulation ("PBR") Initiative outlining the PBR
framework applicable to distribution utilities in Alberta, including
FortisAlberta, for a five-year term commencing January 1, 2013. For
further information on these regulatory decisions, refer to the
"Regulatory Highlights" and "Business Risk Management" sections of
this MD&A. 
Part VI.1 Tax: Under the terms of the Corporation's first preference
shares, the Corporation is subject to tax under Part VI.1 of the
Income Tax Act (Canada) associated with dividends on its first
preference shares. For corporations subject to Part VI.1 tax, there
is an equivalent Part I tax deduction. As permitted under the Income
Tax Act (Canada), a corporation may allocate its Part VI.1 tax
liability and equivalent Part I tax deduction to its related
subsidiaries. In the past, Fortis has allocated these items to
Maritime Electric, Newfoundland Power and FortisOntario.  
Upon transition to US GAAP, the Corporation reduced its consolidated
opening 2012 retained earnings by $20 million to reflect the impact
of differences between enacted and substantively enacted tax
legislation associated with prior assessments and payments of Part
VI.1 taxes, and the recovery of Part I taxes. The adjustment was done
as US GAAP requires tax provisions to be based on enacted legislation
versus substantively enacted legislation. A number of legislative
amendments to Part VI.1 tax in Canada have yet to be enacted. The
above-noted transitional US GAAP adjustment will reverse through the
Corporation's earnings in future periods when the legislation is
finally enacted, which is expected in 2013, or as reassessment of
corporate taxation years, upon which the enacted versus the
substantively enacted rates were used to calculate taxes payable
under US GAAP, become statute barred. The statute-barred reversals
will occur between 2012 and 2016 and will increase earnings during
these years. During the third quarter of 2012, Newfoundland Power
recorded a favourable $2.5 million adjustment to income taxes
associated with statute-barred Part VI.1 taxes. 
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 constitute the electricity
distribution system in Port Colborne.  
Acquisition of Turks and Caicos Utilities Limited: In August 2012
Fortis Turks and Caicos acquired Turks and Caicos Utilities Limited
("TCU") for an aggregate purchase price of approximately $13 million
(US$13 million), inclusive of debt assumed of $5 million (US$5
million). TCU is a regulated electric utility operating pursuant to a
50-year licence expiring in 2036. The utility serves more than 2,000
residential and commercial customers on Grand Turk and Salt Cay with
a diesel-fired generating capacity of approximately 9 MW. 
Hotel Acquisition: In October 2012 Fortis Properties acquired the
126-room StationPark All Suite Hotel ("StationPark Hotel") in London,
Ontario for approximately $13 million.  
Pending Acquisition of the Electrical Utility Assets from the City of
Kelowna: FortisBC Electric has offered to purchase the City of
Kelowna's electrical utility assets, which currently serve
approximately 15,000 customers, for approximately $55 million.
FortisBC Electric provides the City of Kelowna with electricity under
a wholesale tariff and has operated and maintained the City of
Kelowna's electrical utility assets since 2000. Closing of the
transaction is subject to certain conditions and receipt of certain
approvals, including regulatory approval. The parties are working
towards closing the transaction by the end of the first quarter of
2013. 
Expropriation of Shares in Belize Electricity: The Government of
Belize ("GOB") expropriated the Corporation's common share ownership
in Belize Electricity in June 2011. The Corporation is challenging
the legality of the expropriation in the Belize Courts. Although the
GOB initiated contact with Fortis, there have been no settlement
negotiations to date on the fair value compensation owing to Fortis
as a result of the expropriation. For further information, refer to
the "Business Risk Management" section of this MD&A. 
Transition to US GAAP:  Effective January 1, 2012, Fortis
retroactively adopted US GAAP with the restatement of comparative
reporting periods. For further information, refer to the "New
Accounting Standards and Policies" section of this MD&A.  
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
Holdings Inc. ("FHI") assumed 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 third quarter and year-to-date periods ended September 30,
2012 and September 30, 2011 are provided in the following table.  


 
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Consolidated Financial Highlights (Unaudited)                               
Periods Ended                                                               
 September 30                           Quarter                Year-to-Date 
($ millions, except                                                         
 for common share                                                           
 data)                   2012     2011 Variance     2012      2011 Variance 
----------------------------------------------------------------------------
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Revenue                   714      699       15    2,655     2,704      (49)
Energy Supply Costs       235      246      (11)   1,092     1,207     (115)
Operating Expenses        203      200        3      621       619        2 
Depreciation and                                                            
 Amortization             118      104       14      351       309       42 
Other Income                                                                
 (Expenses), Net            1       22      (21)      (2)       34      (36)
Finance Charges            93       89        4      276       274        2 
Income Taxes                7       12       (5)      44        59      (15)
----------------------------------------------------------------------------
Net Earnings               59       70      (11)     269       270       (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Earnings                                                                
 Attributable to:                                                           
  Non-Controlling                                                           
   Interests                3        3        -        7         7        - 
  Preference Equity                                                         
   Shareholders            11       11        -       34        34        - 
  Common Equity                                                             
   Shareholders            45       56      (11)     228       229       (1)
----------------------------------------------------------------------------
  Net Earnings             59       70      (11)     269       270       (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic Earnings per                                                          
 Common Share ($)        0.24     0.30    (0.06)    1.20      1.28    (0.08)
Diluted Earnings per                                                        
 Common Share ($)        0.24     0.30    (0.06)    1.19      1.27    (0.08)
Weighted Average                                                            
 Number of Common                                                           
 Shares Outstanding                                                         
 (# millions)           190.2    186.5      3.7    189.6     179.5     10.1 
----------------------------------------------------------------------------
Cash Flow from                                                              
 Operating                                                                  
 Activities               221      151       70      804       684      120 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                              Revenue Variances                             

 
Favourable 


 
--  An increase in gas delivery rates and the base component of electricity
    rates at most of the regulated utilities, consistent with rate
    decisions, reflecting ongoing investment in energy infrastructure and
    forecasted certain higher expenses recoverable from customers 
--  Net transmission revenue of approximately $3.5 million recognized for
    the quarter and $6.5 million recognized year to date at FortisAlberta,
    as a result of the 2012 distribution revenue requirements decision
    received in April 2012 
--  Higher gas transportation volumes to industrial customers 
--  Increased electricity sales at FortisBC Electric, Newfoundland Power,
    Maritime Electric a
nd Fortis Turks and Caicos for the quarter and year
    to date and at FortisOntario for the quarter 
--  The flow through in customer electricity rates of higher energy supply
    costs, where applicable, at most of the regulated electric utilities 
--  Growth in the number of customers, driven by FortisAlberta 
--  Differences in the amount of PBR incentives refunded, and flow-through
    adjustments owing, to FortisBC Electric's customers period over period 
--  Higher Hospitality revenue at Fortis Properties, driven by revenue from
    the Hilton Suites Winnipeg Airport hotel ("Hilton Suites Hotel"), which
    was acquired in October 2011 
--  Increased non-regulated hydroelectric production in Belize year to date,
    due to higher rainfall 
--  Approximately $1 million for the quarter and $5 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 

 
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, which reduced revenue year to date 
--  The flow through in customer electricity rates of lower energy supply
    costs at Caribbean Utilities for the quarter, due to a decrease in the
    cost of fuel period over period 
--  Lower average gas consumption by residential and commercial customers
    year to date 
--  Revenue at Newfoundland Power in 2011 reflected the favourable impact of
    support structure arrangements with Bell Aliant Inc. ("Bell Aliant") 
--  Decreased non-regulated hydroelectric production in Belize for the
    quarter, due to lower rainfall 
--  Decreased electricity sales at Caribbean Utilities for the quarter and
    year to date and at FortisOntario year to date 
 
                                                                            
             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, which reduced energy supply costs year to date 
--  Lower average gas consumption by residential and commercial customers
    year to date, which reduced natural gas purchases 
--  Decreased fuel prices at Caribbean Utilities for the quarter 
--  Decreased electricity sales at Caribbean Utilities for the quarter and
    year to date and at FortisOntario year to date, which reduced fuel and
    power purchases 

 
Unfavourable 


 
--  Increased fuel prices at Caribbean Utilities year to date and increased
    purchased power costs at FortisBC Electric and FortisOntario for the
    quarter and year to date 
--  An increase in the base amount of energy supply costs expensed at
    Maritime Electric in accordance with the operation of the Energy Cost
    Adjustment Mechanism 
--  Increased electricity sales at FortisBC Electric, Newfoundland Power,
    Maritime Electric and Fortis Turks and Caicos for the quarter and year
    to date and at FortisOntario for the quarter, which increased fuel and
    power purchases 
--  Approximately $1 million for the quarter and $3 million year to date
    associated with unfavourable foreign currency translation 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                        Operating Expenses Variances                        

 
Unfavourable 


 
--  General inflationary and employee-related cost increases at the
    Corporation's regulated utilities, and timing of certain expenses at
    FortisBC Electric during 2012 
--  Operating expenses associated with the Hilton Suites Hotel, which was
    acquired in October 2011 

 
Favourable 


 
--  Reduced operating expenses at the FortisBC Energy companies during 2012,
    mainly due to the accrual of non-asset retirement obligation ("non-ARO")
    removal costs in depreciation, effective January 1, 2012, the timing of
    certain expenditures during 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, which decreased operating expenses year to date 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
               Depreciation and Amortization Expense 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, which decreased depreciation year to date 
--  Lower depreciation rates at FortisAlberta and FortisBC Electric,
    effective January 1, 2012, as a result of the 2012 revenue requirements
    decisions received in April 2012 and August 2012, respectively 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                   Other Income (Expenses), Net Variances                   

 
Unfavourable 


 
--  The favourable impact in 2011 of the $17 million (US$17.5 million) ($11
    million after tax) fee paid to Fortis in July 2011 following the
    termination of a Merger Agreement between Fortis and Central Vermont
    Public Service Corporation ("CVPS") 
--  Approximately $0.5 million ($0.5 million after tax) and $8.5 million
    ($7.5 million after tax) of costs incurred in the third quarter and
    year-to-date 2012, respectively, related to the pending acquisition of
    CH Energy Group 
--  Foreign exchange losses of approximately $3 million and $2.5 million for
    the third quarter and year-to-date 2012, respectively, associated with
    the translation of the US dollar-denominated long-term other asset
    representing the book value of the Corporation's expropriated investment
    in Belize Electricity. A net foreign exchange gain of approximately $1.5
    million ($2.5 million after tax) was recognized for the third quarter
    and year-to-date 2011 related to the above item. 
--  Lower capitalized equity component of allowance for funds used during
    construction ("AFUDC"), mainly at the FortisBC Energy companies 
--  An approximate $1 million gain on the sale of property at FortisAlberta
    during the first quarter of 2011 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                          Finance Charges Variances                         

 
Unfavourable 


 
--  Higher long-term debt levels in support of the utilities' capital
    expenditure programs 
--  Lower capitalized debt component of AFUDC at the regulated utilities,
    mainly at the FortisBC Energy companies 

 
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 faci
lity ("Waneta
    Expansion") 
--  The expropriation of Belize Electricity and the resulting discontinuance
    of the consolidation method of accounting for the utility, effective
    June 20, 2011, which decreased finance charges year to date 
--  Lower short-term borrowings at the regulated utilities year to date,
    driven by the FortisBC Energy companies 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                           Income Taxes Variances                           

 
Favourable 


 
--  Lower statutory corporate income tax rates and lower earnings before
    income taxes 
--  Differences in the deductions for income tax purposes compared to
    accounting purposes period over period 
 
                                                                            
             Factors Contributing to Quarterly Earnings Variance            

 
Unfavourable 


 
--  Higher corporate expenses, due to the favourable impact in 2011 of the
    $11 million after-tax fee paid to Fortis in July 2011 following the
    termination of a Merger Agreement between Fortis and CVPS, and a foreign
    exchange loss of approximately $3 million after tax recognized in the
    third quarter of 2012 compared to a net foreign exchange gain of
    approximately $2.5 million after tax recognized in the third quarter of
    2011 
--  Decreased non-regulated hydroelectric production in Belize, due to lower
    rainfall 
--  A higher loss at the FortisBC Energy companies, largely related to the
    unfavourable impact of the difference in the timing of the recognition
    of revenue associated with seasonal gas consumption and certain
    increased regulator-approved expenses in 2012, lower capitalized AFUDC
    and lower-than-expected customer additions in 2012. The above items were
    partially offset by higher gas transportation volumes to industrial
    customers and the timing of certain operating and maintenance expenses
    during 2012. 

 
Favourable 


 
--  Increased earnings at FortisAlberta, mainly due to higher net
    transmission revenue, rate base growth and the timing of operating
    expenses during 2012, partially offset by a lower allowed ROE 
--  Increased earnings at FortisBC Electric, due to rate base growth, higher
    pole-attachment revenue and lower-than-expected finance charges in 2012 
--  Increased earnings at Newfoundland Power, mainly due to lower effective
    income taxes and a higher allowed ROE, partially offset by the impact of
    the support structure arrangements with Bell Aliant during 2011 
 
                                                                            
           Factors Contributing to Year-to-Date Earnings Variance           

 
Unfavourable 


 
--  Higher corporate expenses due to: (i) the favourable impact in 2011 of
    the $11 million after-tax fee paid to Fortis in July 2011 following the
    termination of a Merger Agreement between Fortis and CVPS; (ii)
    approximately $7.5 million, after tax, of costs incurred year-to-date
    2012 related to the pending acquisition of CH Energy Group; and (iii) a
    foreign exchange loss of approximately $2.5 million after tax recognized
    year-to-date 2012 compared to a net foreign exchange gain of
    approximately $2.5 million after tax recognized year-to-date 2011. The
    increase in corporate expenses was partially offset by lower finance
    charges, primarily due to higher capitalized interest associated with
    financing of the construction of the Corporation's 51% controlling
    ownership interest in the Waneta Expansion. 

 
Favourable 


 
--  Increased earnings at FortisAlberta, due to rate base growth, higher net
    transmission revenue, the timing of operating expenses during 2012,
    lower effective income taxes and lower-than-expected finance charges,
    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 Newfoundland Power, for the same reasons discussed
    above for the quarter, in addition to increased electricity sales year
    to date 
--  Increased earnings at the FortisBC Energy companies, mainly due to rate
    base growth, higher gas transportation volumes to industrial customers
    and timing of certain operating and maintenance expenses during 2012,
    partially offset by lower-than-expected customer additions in 2012,
    lower capitalized AFUDC and the unfavourable impact of the difference in
    the timing of recognition of revenue associated with seasonal gas
    consumption and certain increased regulator-approved expenses in 2012 
--  Increased non-regulated hydroelectric production in Belize, due to
    higher rainfall 

 
SEGMENTED RESULTS OF OPERATIONS 


 
----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders           
 (Unaudited)                                                                
Periods Ended September 30                 Quarter             Year-to-Date 
($ millions)                 2012    2011 Variance    2012    2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Regulated Gas Utilities -                                                   
 Canadian                                                                   
  FortisBC Energy                                                           
   Companies                   (6)     (4)      (2)     89      86        3 
----------------------------------------------------------------------------
Regulated Electric                                                          
 Utilities -                                                                
Canadian                                                                    
  FortisAlberta                26      19        7      73      58       15 
  FortisBC Electric            13      10        3      38      38        - 
  Newfoundland Power            9       8        1      28      24        4 
  Other Canadian Electric                                                   
   Utilities                    6       6        -      18      18        - 
----------------------------------------------------------------------------
                               54      43       11     157     138       19 
----------------------------------------------------------------------------
Regulated Electric                                                          
 Utilities - Caribbean          7       6        1      16      16        - 
Non-Regulated - Fortis                                                      
 Generation                     5       8       (3)     15      13        2 
Non-Regulated - Fortis                                                      
 Properties                     8       9       (1)     17      18       (1)
Corporate and Other           (23)     (6)     (17)    (66)    (42)     (24)
----------------------------------------------------------------------------
Net Earnings Attributable                                                   
 to Common Equity                                                           
 Shareholders                  45      56      (11)    228     229       (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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) 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                              Quarter              Year-to-Date 
Periods Ended September                                                     
 30                        2012    2011  Variance     2012    2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas Volumes (petajoules                                                     
 ("PJ"))                     26      23         3      138     140       (2)
Revenue ($ millions)        192     197        (5)   1,004   1,090      (86)
(Loss) Earnings ($                                                          
 millions)                   (6)     (4)       (2)      89      86        3 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1) Includes FortisBC Energy Inc. ("FEI"), FortisBC Energy (Vancouver     
    Island) Inc. ("FEVI") and FortisBC Energy (Whistler) Inc. ("FEWI")    
                                                                          
           Factors Contributing to Quarterly Gas Volumes Variance           

 
Favourable 


 
--  Higher gas transportation volumes to industrial customers, due to
    certain customers switching to natural gas from alternative sources of
    fuel as a result of lower natural gas prices 
 
                                                                            
          Factors Contributing to Year-to-Date Gas Volumes Variance         

 
Unfavourable 


 
--  Lower average gas consumption by residential and commercial customers,
    driven by overall warmer temperatures 

 
Favourable 


 
--  Higher gas transportation volumes to industrial customers, for the same
    reason discussed above for the quarter 

 
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 September 30,
2012, the total number of customers served by the FortisBC Energy
companies was approximately 938,000. 
The FortisBC Energy companies earn approximately the same margin
regardless of whether a customer contracts for the purchase and
delivery of natural gas or only for the delivery of natural gas. As a
result of the operation of regulator-approved deferral mechanisms,
changes in consumption levels and the commodity cost of natural gas
from those forecast to set residential and commercial customer gas
rates do not materially affect earnings. 
Seasonality has a material impact on the earnings of the FortisBC
Energy companies as a major portion of the gas distributed is used
for space heating. Most of the annual earnings of the FortisBC Energy
companies are realized in the first and fourth quarters.  


 
                                                                            
             Factors Contributing to Quarterly Revenue Variance             

 
Unfavourable 


 
--  Lower commodity cost of natural gas charged to 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 certain higher expenses recoverable from
    customers as reflected in the 2012-2013 revenue requirements decision
    received in April 2012 
--  Higher gas transportation volumes to industrial customers 
 
                                                                            
            Factors Contributing to Year-to-Date Revenue Variance           

 
Unfavourable 


 
--  The same factors discussed above for the quarter 
--  Lower average gas consumption by residential and commercial customers 

 
Favourable 


 
--  The same factors discussed above for the quarter 
 
                                                                            
            Factors Contributing to Quarterly Earnings Variance             

 
Unfavourable 


 
--  The difference in the timing of recognition of revenue and certain
    expenses in 2012. Revenue is recognized based on seasonal gas
    consumption while certain expenses are generally incurred evenly
    throughout the year, which, combined with an approved increase in those
    expenses in 2012, has resulted in timing differences contributing to
    lower earnings quarter over quarter 
--  Lower capitalized AFUDC, due to lower assets under construction period
    over period 
--  Lower-than-expected customer additions in 2012 

 
Favourable 


 
--  Higher gas transportation volumes to industrial customers 
--  The timing of certain operating and maintenance expenses during 2012 
 
                                                                            
           Factors Contributing to Year-to-Date Earnings Variance           

 
Favourable 


 
--  Rate base growth, due to continued investment in energy infrastructure 
--  The same factors discussed above for the quarter 

 
Unfavourable 


 
--  Lower-than-expected customer additions in 2012 
--  Lower capitalized AFUDC, for the same reason discussed above for the
    quarter 
--  The difference in the timing of recognition of revenue and certain
    expenses in 2012, for the reasons discussed above for the quarter, which
    reduced earnings year to date compared to the same period last year 

 
REGULATED ELECTRIC UTILITIES - CANADIAN 
FORTISALBERTA 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                              Quarter               Year-to-Date
Periods Ended                                                               
 September 30              2012     2011 Variance     2012     2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Deliveries                                                           
 (gigawatt hours                                                            
 ("GWh"))                 4,099    3,911      188   12,434   12,135      299
Revenue ($ millions)        117      103       14      335      306       29
Earnings ($ millions)        26       19        7       73       58       15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                                            
        Factors Contributing to Quarterly Energy Deliveries Variance        

 
Favourable 


 
--  Higher average consumption by oilfield and commercial customers, due to
    increased activity mainly as a result of higher market prices for oil 
--  Higher average consumption by residential customers, due to warmer
    temperatures which increased air conditioning load 
--  Growth in the number of customers, with the total number of customers
    increasing by approximately 9,000 year over year as at September 30,
    2012, driven by favourable economic conditions 
--  Higher average consumption by farm and irrigation customers, due to
    warmer temperatures and lower precipitation levels 
 
                                 
                                           
       Factors Contributing to Year-to-Date Energy Deliveries Variance      

 
Favourable 


 
--  Higher average consumption by oilfield and commercial customers, for the
    same reason discussed above for the quarter 
--  Growth in the number of customers, for the same reason discussed above
    for the quarter 

 
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 
--  Net transmission revenue of approximately $3.5 million recognized for
    the quarter and $6.5 million recognized year to date. 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 forecasted.
--  Growth in the number of customers 
--  An increase in franchise fee revenue of approximately $1 million for the
    quarter and $3 million year to date 

 
Unfavourable 


 
--  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 

 
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. 
--  The same factor discussed above for the quarter 
 
                                                                            
             Factors Contributing to Quarterly Earnings Variance            

 
Favourable 


 
--  Net transmission revenue of approximately $3.5 million recognized for
    the quarter and $6.5 million recognized year to date, as a result of the
    distribution revenue requirements decision received in April 2012 
--  Rate base growth, due to continued investment in energy infrastructure 
--  The timing of operating expenses during 2012 

 
Unfavourable 


 
--  A lower allowed ROE, as discussed above 
 
                                                                            
           Factors Contributing to Year-to-Date Earnings Variance           

 
Favourable 


 
--  The same factors discussed above for the quarter 
--  Lower effective income taxes, primarily 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 
--  Lower-than-expected finance charges in 2012 

 
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                                                               
 September 30              2012     2011 Variance     2012     2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales                                                           
 (GWh)                      728      713       15    2,313    2,300       13
Revenue ($ millions)         71       67        4      225      215       10
Earnings ($ millions)        13       10        3       38       38        -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 electrical    
    utility assets owned by the City of Kelowna. Excludes the non-        
    regulated generation operations of FortisBC Inc.'s wholly owned       
    partnership, Walden Power Partnership                                 
                                                                          
             Factors Contributing to Quarterly and Year-to-Date             
                         Electricity Sales Variances                        

 
Favourable 


 
--  Growth in the number of customers 
--  Higher average consumption, due to differences in weather conditions
    period over period 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                              Revenue Variances                             

 
Favourable 


 
--  A net increase in customer electricity rates, effective January 1, 2012,
    mainly due to ongoing investment in energy infrastructure and forecasted
    certain higher expenses recoverable from customers as reflected in the
    2012-2013 revenue requirements decision received in August 2012 
--  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, which increased
    revenue year to date 
--  Higher pole-attachment revenue 
--  Differences in the amount of PBR incentives refunded, and flow-through
    adjustments owing, to customers period over period 
--  The 2.1% and 0.6% increase in electricity sales for the quarter and year
    to date, respectively 
 
                                                                            
             Factors Contributing to Quarterly Earnings Variance            

 
Favourable 


 
--  Rate base growth, due to continued investment in energy infrastructure 
--  Higher pole-attachment revenue 
--  Lower-than-expected finance charges in 2012. As approved in the 2012-
    2013 revenue requirements decision received in August 2012, variances
    between actual finance charges and those forecasted in determining
    customer electricity rates, beginning January 1, 2012, are no longer
    permitted deferral account treatment and, therefore, favourably impacted
    earnings in 
2012 
 
                                                                            
           Factors Contributing to Year-to-Date Earnings Variance           

 
Favourable 


 
--  The same factors discussed above for the quarter 

 
Unfavourable 


 
--  The expiry of the PBR mechanism on December 31, 2011. Year-to-date 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 decision
    received in August 2012, variances between actual electricity revenue
    and purchased power costs and those used in determining customer
    electricity rates are subject to full deferral account treatment and,
    therefore, did not impact earnings year-to-date 2012.  

 
NEWFOUNDLAND POWER 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                             Quarter                Year-to-Date
Periods Ended                                                               
 September 30             2012     2011 Variance      2012     2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales                                                           
 (GWh)                     940      923       17     4,113    4,026       87
Revenue ($ millions)       100      101       (1)      422      417        5
Earnings ($ millions)        9        8        1        28       24        4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                         Electricity Sales Variances                        

 
Favourable 


 
--  Growth in the number of customers 
--  Higher concentration of electric-versus-oil heating in new home
    construction combined with economic growth, which increased consumption 

 
Unfavourable 


 
--  Sunnier weather conditions, which reduced average consumption 
 
                                                                            
             Factors Contributing to Quarterly Revenue Variance             

 
Unfavourable 


 
--  Revenue for 2011 included amounts related to support structure
    arrangements, which were in place with 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. 

 
Favourable 


 
--  The 1.8% increase in electricity sales 
 
                                                                            
            Factors Contributing to Year-to-Date Revenue Variance           

 
Favourable 


 
--  The 2.2% 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 and Year-to-Date             
                             Earnings Variances                             

 
Favourable 


 
--  Lower effective income taxes, primarily due to lower Part VI.1 taxes,
    including the favourable impact of reversals of statute-barred Part VI.1
    taxes period over period, and a lower statutory income tax rate. For
    further information on Part VI.1 tax, refer to the "Significant Items"
    section of this MD&A. 
--  A higher allowed ROE, effective January 1, 2012, which is being accrued
    in 2012, as approved by the regulator, as a decrease in operating
    expenses for deferred recovery from customers 
--  Electricity sales growth year to date 

 
Unfavourable 


 
--  The impact of the support structure arrangements with Bell Aliant during
    2011, as discussed above 
--  Approximately $1 million in additional operating labour and maintenance
    costs incurred as a result of Tropical Storm Leslie in September 2012 
--  Higher depreciation expense, due to continued investment in energy
    infrastructure 

 
OTHER CANADIAN ELECTRIC UTILITIES (1) 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                              Quarter               Year-to-Date
Periods Ended                                                               
 September 30              2012     2011 Variance     2012     2011 Variance
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Electricity Sales                                                           
 (GWh)                      595      582       13    1,803    1,798        5
Revenue ($ millions)         91       87        4      264      256        8
Earnings ($ millions)         6        6        -       18       18        -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Maritime Electric and FortisOntario. FortisOntario mainly    
    includes Canadian Niagara Power, Cornwall Electric and Algoma Power.  
                                                                          
        Factors Contributing to Quarterly Electricity Sales Variance        

 
Favourable 


 
--  Higher average consumption by commercial customers in the agricultural
    processing sector on Prince Edward Island ("PEI") 
--  Higher average consumption by residential customers and several large
    commercial customers in Ontario 
 
                                                                            
       Factors Contributing to Year-to-Date Electricity Sales Variance      

 
Favourable 


 
--  Higher average consumption by commercial customers in the agricultural
    processing sector on PEI 
--  Growth in the number of, and higher average consumption by, residential
    customers on PEI and an increase in the number of such customers using
    electricity for home heating 

 
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 


 
--  The overall 2.2% and 0.3% increase in electricity sales for the quarter
    and year to date, respectively, 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 
--  Increased customer rates at FortisOntario 
 
                                                                            
             Factors Contributing to Quarterly and Year-to-Date             
                             Earnings Variances                             

 
Favourable 


 
--  Lower operating expenses at FortisOntario for the quarter, largely due
    to the timing of certain operating expenses during 2012 
--  Electricity sales growth 
--  Increased customer rates at F
ortisOntario 

 
Unfavourable 


 
--  Increased depreciation expense and finance charges at Maritime Electric,
    due to continued investment in energy infrastructure and increased
    short-term borrowings, respectively 
--  Higher operating expenses at FortisOntario year to date, largely due to
    an increase in employee-related costs and the timing of certain
    operating expenses during 2012 

 
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1) 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                            Quarter                Year-to-Date 
Periods Ended                                                               
 September 30            2012     2011 Variance      2012     2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average US:CDN                                                              
 Exchange Rate (2)       1.00     0.98     0.02      1.00     0.98     0.02 
----------------------------------------------------------------------------
Electricity Sales                                                           
 (GWh)                    197      197        -       547      744     (197)
Revenue ($ millions)       72       74       (2)      202      234      (32)
Earnings ($                                                                 
 millions)                  7        6        1        16       16        - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which
    Fortis holds an approximate 60% controlling interest; three small     
    wholly owned utilities in the Turks and Caicos Islands, which include 
    Turks and Caicos Utilities Ltd., acquired in August 2012, FortisTCI   
    Limited and Atlantic Equipment & Power (Turks and Caicos) Ltd.        
    (collectively "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 "Significant Items" and         
    "Business Risk Management" sections of this MD&A.                     
                                                                          
(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 Electricity Sales Variance        

 
Favourable 


 
--  Growth in the number of customers 
--  Warmer temperatures experienced in the Turks and Caicos Islands, which
    increased air conditioning load 
--  Higher tourism activity in the Turks and Caicos Islands 
--  Electricity sales in the Turks and Caicos Islands during the third
    quarter of 2011 were reduced, due to the early and extended closure of a
    certain hotel and other commercial customers resulting from a hurricane 

 
Unfavourable 


 
--  Higher rainfall experienced on Grand Cayman, which decreased air
    conditioning load 
 
                                                                            
       Factors Contributing to Year-to-Date Electricity Sales Variance      

 
Unfavourable 


 
--  The expropriation of Belize Electricity and the resulting discontinuance
    of the consolidation method of accounting for the utility, effective
    June 20, 2011. Excluding Belize Electricity, electricity sales decreased
    approximately 0.5% year to date. 
--  The same factor discussed above for the quarter 

 
Favourable 


 
--  The same factors discussed above for the quarter 
 
                                                                            
             Factors Contributing to Quarterly Revenue Variance             

 
Unfavourable 


 
--  The flow through in customer electricity rates of lower energy supply
    costs at Caribbean Utilities, due to a decrease in the cost of fuel
    period over period 
--  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 


 
--  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 $1 million for the quarter and $5 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 
--  An increase in base electricity rates at Caribbean Utilities, effective
    June 1, 2012 
 
                                                                            
            Factors Contributing to Year-to-Date Revenue Variance           

 
Unfavourable 


 
--  The expropriation of Belize Electricity and the resulting discontinuance
    of the consolidation method of accounting for Belize Electricity,
    effective June 20, 2011, which decreased revenue by approximately $45
    million period over period 
--  Decreased electricity sales at Caribbean Utilities 
--  The discontinuance of government subsidization of Fortis Turks and
    Caicos' South Caicos operations, as discussed above for the quarter 

 
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
    period over period 
--  The same factors discussed above for the quarter 
 
                                                                            
             Factors Contributing to Quarterly Earnings Variance            

 
Favourable 


 
--  Lower finance charges at Caribbean Utilities 
--  Increased electricity sales at Fortis Turks and Caicos 

 
Unfavourable 


 
--  Overall higher depreciation expense, and higher finance charges at
    Fortis Turks and Caicos, largely due to investment in utility capital
    assets 
--  Decreased electricity sales at Caribbean Utilities 
 
                                                                            
           Factors Contributing to Year-to-Date Earnings Variance           

 
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, driven by the timing of
    capital projects 
--  Increased electricity sales at Fortis Turks and Caicos 

 
Unfavourable 


 
--  Overall higher depreciation expense and finance charges, for the same
    reason discussed above for the quarter 
--  Increased operating expenses at Fortis Turks and Caicos, mainly
    associated with the timing of capital projects 

 
Fortis Turks and Caicos acquired TCU in August 2012 for an 
aggregate
purchase price of approximately $13 million (US$13 million),
inclusive of debt assumed of $5 million (US$5 million). For further
information refer to the "Significant Items" section of this MD&A.  
NON-REGULATED - FORTIS GENERATION (1) 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                            Quarter                Year-to-Date 
Periods Ended                                                               
 September 30            2012     2011 Variance      2012     2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Energy Sales (GWh)         81      111      (30)      256      277      (21)
Revenue ($ millions)        8       11       (3)       26       25        1 
Earnings ($                                                                 
 millions)                  5        8       (3)       15       13        2 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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                                                         
                                                                          
           Factor Contributing to Quarterly Energy Sales Variance           

 
Unfavourable 


 
--  Decreased production in Belize and Upstate New York, due to lower
    rainfall 
 
                                                                            
         Factors Contributing to Year-to-Date Energy Sales Variance         

 
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, driven by higher rainfall during the
    first half of 2012 
 
                                                                            
       Factor Contributing to Quarterly Revenue and Earnings Variances      

 
Unfavourable 


 
--  Decreased production in Belize 
 
                                                                            
     Factors Contributing to Year-to-Date Revenue and Earnings Variances    

 
Favourable 


 
--  Increased production in Belize 

 
Unfavourable 


 
--  Decreased production in Upstate New York 

 
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 the generator was being repaired due to the
electrical damage. The generating facility is expected to be online
by the end of 2012. 
NON-REGULATED - FORTIS PROPERTIES (1) 


 
----------------------------------------------------------------------------
Financial Highlights                                                        
 (Unaudited)                            Quarter                Year-to-Date 
Periods Ended                                                               
 September 30            2012     2011 Variance      2012     2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Hospitality -                                                               
 Revenue per                                                                
 Available Room                                                             
 ("RevPAR") ($)         94.04    94.83    (0.79)    82.09    80.54     1.55 
Real Estate -                                                               
 Occupancy Rate (as                                                         
 at, %) (2)              91.8     94.2     (2.4)     91.8     94.2     (2.4)
----------------------------------------------------------------------------
Hospitality Revenue                                                         
 ($ millions)              48       47        1       130      123        7 
Real Estate Revenue                                                         
 ($ millions)              17       16        1        51       50        1 
----------------------------------------------------------------------------
  Total Revenue ($                                                          
   millions)               65       63        2       181      173        8 
----------------------------------------------------------------------------
Earnings ($                                                                 
 millions)                  8        9       (1)       17       18       (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Fortis Properties owns and operates 23 hotels, collectively           
    representing more than 4,400 rooms, in eight Canadian provinces,      
    including the acquisition of the StationPark Hotel in London, Ontario,
    which was acquired in October 2012 for approximately $13 million.     
    Fortis Properties also owns and operates approximately 2.7 million    
    square feet of commercial office and retail space primarily in        
    Atlantic Canada.                                                      
                                                                          
(2) Reduced occupancy rate is primarily due to increased vacancy in New   
    Brunswick.                                                            
                                                                          
             Factors Contributing to Quarterly Revenue Variance             

 
Favourable 


 
--  Increased Hospitality Division revenue, driven by contribution from the
    Hilton Suites Hotel, which was acquired in October 2011 

 
Unfavourable 


 
--  A 0.8% decrease in RevPar at the Hospitality Division. Excluding the
    impact of the Hilton Suites Hotel, RevPAR was $93.20 for the third
    quarter of 2012, a decrease of 1.7% quarter over quarter. The decrease
    in RevPAR was due to an overall 2.0% decrease in hotel occupancy,
    partially offset by an overall 0.3% increase in the average daily room
    rate. Hotel occupancy in Atlantic Canada and central Canada decreased,
    while occupancy in western Canada increased. The average daily room rate
    increased in western Canada and central Canada, and decreased in
    Atlantic Canada.  
 
                                                                            
            Factors Contributing to Year-to-Date Revenue Variance           

 
Favourable 


 
--  A 1.9% increase in RevPAR at the Hospitality Division, driven by
    contribution from the Hilton Suites Hotel 
--  Excluding the impact of the Hilton Suites Hotel, RevPAR was $80.80 year-
    to-date 2012, an increase of 0.3% period over period. The increase in
    RevPAR was due to an overall 1.7% increase in the average daily room
    rate, partially offset by an overall 1.4% 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                             

 
Unfavourable 


 
--  Lower performance at the Hospitality Division, excluding the Hilton
    Suites Hotel, primarily due to the impact of decreased occupancy at
    hotel operations in Atlantic Canada and central Canada, and increased
    depreciation due to capital additions and improvements 
--  A $0.5 million gain on the sale of the Viking Mall during the first
    quarter of 2011 

 
Favourable 


 
--  Contribution from the Hilton Suites Hotel 

 
CORPORATE AND OTHER (1) 


 
----------------------------------------------------------------------------
Financial Highlights (Unaudited)                                            
Periods Ended                                                               
 September 30                           Quarter                Year-to-Date 
($ millions)            2012     2011  Variance     2012     2011  Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue                    5        4         1       18       17         1 
Operating Expenses         2        4        (2)       8        9        (1)
Depreciation and                                                            
 Amortization              -        -         -        1        1         - 
Other Income                                                                
 (Expenses), Net          (3)      20       (23)     (11)      20       (31)
Finance Charges           13       12         1       36       38        (2)
Income Tax                                                                  
 (Recovery) Expense       (1)       3        (4)      (6)      (3)       (3)
----------------------------------------------------------------------------
                         (12)       5       (17)     (32)      (8)      (24)
Preference Share                                                            
 Dividends                11       11         -       34       34         - 
----------------------------------------------------------------------------
Net Corporate and                                                           
 Other Expenses          (23)      (6)      (17)     (66)     (42)      (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Fortis net corporate expenses, net expenses of non-regulated 
    FortisBC Holdings Inc. ("FHI") corporate-related activities and the   
    financial results of FHI's wholly owned subsidiary FortisBC           
    Alternative Energy Services Inc. and FHI's 30% ownership interest in  
    CustomerWorks Limited Partnership ("CWLP"). The contracts between CWLP
    and the FortisBC Energy companies ended on December 31, 2011.         
                                                                          
                     Factors Contributing to Quarterly                      
                  Net Corporate and Other Expenses Variance                 

 
Unfavourable 


 
--  Increased other expenses, net of other income, primarily due to: (i) the
    favourable impact in 2011 of the $17 million (US$17.5 million) ($11
    million after tax) fee paid to Fortis in July 2011 following the
    termination of a Merger Agreement between Fortis and CVPS; (ii)
    approximately $0.5 million ($0.5 million after tax) and $8.5 million
    ($7.5 million after tax) of costs incurred during the third quarter and
    year-to-date 2012, respectively, related to the pending acquisition of
    CH Energy Group; and (iii) foreign exchange losses of approximately $3
    million and $2.5 million for the third quarter and year-to-date 2012,
    respectively, associated with the translation of the US dollar-
    denominated long-term other asset representing the book value of the
    Corporation's expropriated investment in Belize Electricity. During the
    third quarter of 2011, a foreign exchange gain of $7 million associated
    with the translation of the above-noted US dollar-denominated long-term
    other asset was partially offset by a $5.5 million ($4.5 million after
    tax) foreign exchange loss associated with the translation of previously
    hedged US dollar-denominated long-term debt. The favourable net impact
    to earnings during the third quarter of 2011 of the above-noted foreign
    exchange impacts was approximately $2.5 million. 
--  Excluding income tax expense associated with the merger termination fee
    paid to Fortis in July 2011, income tax recovery decreased, primarily
    due to higher Part VI.1 taxes 
 
                                                                            
                    Factors Contributing to Year-to-Date                    
                  Net Corporate and Other Expenses Variance                 

 
Unfavourable 


 
--  The same factors discussed above for the quarter 

 
Favourable 


 
--  Lower finance charges, primarily due to higher capitalized interest
    associated with the financing of the construction of the Corporation's
    51% controlling ownership interest in the Waneta Expansion and the
    impact of the conversion of the Corporation's US$40 million convertible
    debentures into common shares in November 2011. The above decreases were
    partially offset by higher interest on credit facility borrowings in
    2012, due to higher average credit facility borrowings and higher fees
    associated with the increase in the Corporation's committed revolving
    credit facility to $1 billion in May 2012. During the third quarter of
    2011, credit facility borrowings were repaid with a portion of the
    proceeds from the common share offering in June and July 2011. 

 
REGULATORY HIGHLIGHTS 
The nature of regulation and material regulatory decisions and
applications associated with each of the Corporation's regulated gas
and electric utilities year-to-date 2012 are summarized as follows. 


 
NATURE OF REGULATION                                                      
--------------------------------------------------------------------------
                           Allowed                                        
                           Common                                         
Regulated     Regulatory   Equity                            Supportive   
Utility       Authority    (%)      Allowed Returns (%)      Features     
                                                             -------------
                                                             Future or    
                                                             Historical   
                                                             Test Year    
                                                             Used to Set  
                                                             Customer     
                                    2010    2011    2012     Rates        
--------------------------------------------------------------------------
                                            ROE              COS/ROE      
                                    -------------------------             
FEI           British      40       9.50    9.50    9.50     FEI: Prior to
              Columbia                                       January 1,   
              Utilities                                      2010, 50/50  
              Commission                                     sharing of   
              ("BCUC")                                       earnings     
                                                             above or     
                                                             below        
                                                             the allowed  
                   
                                          ROE under a  
                                                             PBR          
                                                             mechanism    
                                                             that expired 
                                                             on           
                                                             December 31, 
                                                             2009 with a  
                                                             two-year     
                                                             phase-out    
FEVI          BCUC         40       10.00   10.00   10.00                 
                                                                          
FEWI          BCUC         40       10.00   10.00   10.00    ROEs         
                                                             established  
                                                             by the BCUC  
                                                             -------------
                                                             Future Test  
                                                             Year         
--------------------------------------------------------------------------
FortisBC      BCUC         40       9.90    9.90    9.90     COS/ROE      
Electric                                                                  
                                                             PBR mechanism
                                                             for 2009     
                                                             through      
                                                             2011: 50/50  
                                                             sharing of   
                                                             earnings     
                                                             above or     
                                                             below the    
                                                             allowed ROE  
                                                             up           
                                                             to an        
                                                             achieved ROE 
                                                             that is 200  
                                                             basis        
                                                             points above 
                                                             or below the 
                                                             allowed      
                                                             ROE - excess 
                                                             to deferral  
                                                             account      
                                                                          
                                                             ROE          
                                                             established  
                                                             by the BCUC  
                                                             -------------
                                                             Future Test  
                                                             Year         
--------------------------------------------------------------------------
FortisAlberta AUC          41       9.00    8.75    8.75     COS/ROE      
                                                                          
                                                             ROE          
                                                             established  
                                                             by the AUC   
                                                             -------------
                                                             Future Test  
                                                             Year         
--------------------------------------------------------------------------
Newfoundland  Newfoundland 45       9.00 +/-8.38 +/-8.80 +/- COS/ROE      
Power         and                   50 bps  50 bps  50 bps                
              Labrador                                                    
              Board of                                                    
              Commissioners                                               
              of                                                          
              Public                                                      
              Utilities                                                   
              ("PUB")                                                     
                                                                          
                                                             The allowed  
                                                             ROE had been 
                                                             set using    
                                                             an automatic 
                                                             adjustment   
                                                             formula tied 
                                                             to long-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         
                                                                          
                                                                          
--------------------------------------------------------------------------
FortisOntario Ontario                                        Canadian     
              Energy                                         Niagara Power
              Board ("OEB")                                  - COS/ROE    
                                                                          
              Canadian     40       8.01    8.01    8.01 (1) Algoma Power 
              Niagara                                        - COS/ROE and
              Power                                                       
                                                             subject to   
                                                             Rural and    
                                                             Remote Rate  
              Algoma Power 40       8.57    9.85    9.85 (1) Protection   
                                                             ("RRRP")     
                                                             Program      
   
                                                                       
              Franchise                                      Cornwall     
              Agreement                                      Electric -   
              Cornwall                                       Price cap    
              Electric                                       with         
                                                             commodity    
                                                             cost flow    
                                                             through      
                                                             -------------
                                                             Canadian     
                                                             Niagara Power
                                                             - 2009       
                                                             historical   
                                                             test year for
                                                             2010, 2011   
                                                             and 2012     
                                                             Algoma Power 
                                                             - 2007       
                                                             historical   
                                                             test         
                                                             year for     
                                                             2010; 2011   
                                                             test year for
                                                             2011         
                                                             and 2012     
--------------------------------------------------------------------------
                                            ROA              COS/ROA      
                                    -------------------------             
Caribbean     Electricity  N/A      7.75 -  7.75 -  7.25 -                
Utilities     Regulatory            9.75    9.75    9.25     Rate-cap     
              Authority                                      adjustment   
              ("ERA")                                        mechanism    
                                                             based on     
                                                             published    
                                                             consumer     
                                                             price indices
                                                                          
                                                             The Company  
                                                             may apply for
                                                             a special    
                                                             additional   
                                                             rate to      
                                                             customers in 
                                                             the          
                                                             event of a   
                                                             disaster,    
                                                             including a  
                                                             hurricane.   
                                                             -------------
                                                             Historical   
                                                             Test Year    
--------------------------------------------------------------------------
Fortis Turks  Utilities    N/A       17.50  17.50    17.50   COS/ROA      
and Caicos    make annual           (2)     (2)     (2)                   
              filings to                                                  
              the Interim                                                 
              Government of                                               
              the Turks and                                               
              Caicos Caicos                                               
              Islands                                                     
              ("Interim                                                   
              Government")                                                
                                                                          
                                                             If the actual
                                                             ROA is lower 
                                                             than the     
                                                             allowed ROA, 
                                                             due to       
                                                             additional   
                                                             costs        
                                                             resulting    
                                                             from a       
                                                             hurricane or 
                                                             other event, 
                                                             the Company  
                                                             may apply for
                                                             an increase  
                                                             in customer  
                                                             rates in the 
                                                             following    
                                                             year.        
                                                                          
                                                             -------------
                                                             Future Test  
                                                             Year         
--------------------------------------------------------------------------
(1) 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 and midstream costs every three  
                          months in order to ensure the flow-through rates  
                          charged to customers ar
e 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.                      
                                                                            
                          - Effective January 1, 2012, rates for typical    
                          residential customers in the Lower Mainland       
                          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 typical    
                          residential customers in the Lower Mainland       
                          decreased by approximately 10%, and rates for     
                          residential customers at FEWI decreased           
                          approximately 6%, following the BCUC's quarterly  
                          review of commodity costs.                        
                                                                            
                          - 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 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. FEI has filed            
                          applications for and received interim rate        
                          approval for two projects under the general       
                          tariff. FEI has also applied for approval of its  
                          LNG sales and dispensing service rate schedule on 
                          a permanent basis. In October 2012 FEI received   
                          approval for rate treatment of expenditures       
                          incurred related to the provision of CNG and LNG  
                          services, under the Greenhouse Gas Reductions     
                          (Clean Energy) Regulation ("GHG Regulation") under
                          the Clean Energy Act.                             
                                                                            
                          - FEI is awaiting a decision from the BCUC on the 
                          Alternative Energy Services Inquiry, which is a   
                          proceeding to determine, among other things,      
                          whether the provision of alternative energy       
                          services is a regulated utility service and       
                          whether FEI or an affiliate, i.e., FortisBC       
                          Alternative Energy Services Inc. ("FAES"), should 
                          provide these services. The alternative energy    
                          services subject to the inquiry include providing 
                          refuelling services for LNG-fuelled vehicles;     
                          owning and operating district energy systems and  
                          various forms of geo-exchange systems; and owning 
                          facilities that upgrade raw biogas into biomethane
                          for the purpose of selling it to customers.       
                                                                            
                          - 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. The
                          evidence in the regulatory proceeding has closed  
                          and a BCUC decision is pending.                   
                                                                            
                          - 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    
                          April 2012 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 timetable
                          sets the evidence portion of the GCOC Proceeding  
                          to take place through to early December 2012 with 
                          an oral hearing 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 Revenue  
                          Requirements Application ("RRA"). 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,   
                          pending the outcome of the GCOC Proceeding as it  
                          may impact 2013 rates. The cumulative impacts of  
                          the 2012-2013 revenue requirements decision, where
                          such impacts were different from those estimated, 
                          were recorded in the second quarter of 2012. The  
                          final rate increases were driven by ongoing       
                          investment in energy infrastructure focused on    
                          system integrity and reliability, 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.            
                                                                            
                          - Following the announcement by the Government of 
                          British Columbia of the GHG Regulation under the  
                          Clean Energy Act, FEI announced an incentive      
                          funding program to assist eligible vehicle        
                          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 eligible operators in purchasing 
                          qualifying LNG-fuelled vehicles. The eligible     
                          applicants for the incentive program are          
                          commercial return-to-base fleet operators of      
                          heavy-duty trucks, buses, vocational vehicles and 
                          marine vessels. Incentives are expected to be     
                          awarded beginning in late 2012 and will cover up  
                          to 80% of the eligible incremental capital costs  
                          in the initial year. Additionally, the GHG        
                          Regulation allows FEI to invest up to $30 million 
                          for LNG fuelling stations and up to $12 million   
                          for CNG fuelling stations. FEI has filed an       
                          application with the BCUC for rate treatment of   
                          the above expenditures under the GHG Regulation.  
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FortisBC Electric         - In August 2012 the BCUC issued its decision on  
                          FortisBC's 2012-2013 RRA, 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.   
                          The resulting final revenue requirements for 2012 
                          and 2013 reflect an allowed ROE and capital       
                          structure unchanged from 2011, pending the outcome
                          of the GCOC Proceeding as it may impact 2013      
                          rates. The decision includes an approved forecast 
                          midyear rate base of approximately $1,112 million 
                          for 2012 and $1,173 million for 2013. Under the   
                          2012-2013 CEP, capital expenditures, before       
                          customer contributions, of approximately $100     
                          million for 2012 and approximately $120 million   
                          for 2013, were approved by the BCUC. Approximately
                          $25 million of approved capital expenditures for  
                          2012 are expected to be incurred in 2013, due to  
                          the timing of receipt in 2012 of the BCUC         
                          decision. The cumulative impacts of the 2012-2013 
                          revenue requirements decision, where such impacts 
                          were different from those estimated, were recorded
                          in the third quarter of 2012. In its decision the 
                          BCUC approved deferral accounts and flow-through  
                          treatment for variances between actual electricity
                          revenue and purchased power
 costs and those       
                          forecasted in determining customer electricity    
                          rates; however, flow-through treatment for finance
                          charges was denied. FortisBC Electric requested,  
                          and the BCUC approved, that the interim refundable
                          1.5% increase in customer rates, effective January
                          1, 2012, as approved by the BCUC in November 2011,
                          be maintained for the remainder of 2012. The      
                          difference between the final approved increase in 
                          2012 customer rates of 0.6% and the interim       
                          increase in customer rates of 1.5% has been       
                          approved for deferral as a regulatory liability in
                          2012, to be used in 2013 to reduce the increase in
                          customer rates to 4.2%, 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.                  
                                                                            
                          - 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 written       
                          hearing process is expected to continue through   
                          the remainder of 2012.                            
                                                                            
                          - In July 2012 FortisBC Electric filed its        
                          Advanced Metering Infrastructure ("AMI")          
                          application, which is currently being reviewed by 
                          the BCUC and various interveners. 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.                                
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FortisAlberta             - 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 that 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. A GCOC Proceeding is      
                          expected to commence late 2012 or early 2013.     
                                                                            
                          - 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 ("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 were provided to the  
                          Alberta Minister for review in September 2012.    
                          Further process has yet to be established and the 
                          government-sanctioned rate freeze has not been    
                          lifted.                                           
                                                                            
                          - 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 which had been requested by
                          the utilities, but would exam
ine 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, where such impacts were    
                          different from those estimated, 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 for  
                          2012. The AUC did not approve the continuation of 
                          the deferral of transmission volume variances     
                          associated with FortisAlberta's AESO charges      
                          deferral account for 2012. The deferral of        
                          transmission volume variances, however, was       
                          reinstated, effective January 1, 2013, per the    
                          AUC's generic decision on its PBR Initiative ("PBR
                          Decision") as discussed further.                  
                                                                            
                          - 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.     
                          CAREA has not sought leave to appeal this         
                          decision.                                         
                                                                            
                          - In June 2012 AESO filed with the AUC a Customer 
                          Contribution Policy Application and an 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. Decisions on the applications 
                          are not expected until 2013.                      
                                                                            
                          - In September 2012 the AUC issued a generic PBR  
                          Decision outlying the PBR framework applicable to 
                          distribution utilities in Alberta, including      
                          FortisAlberta, for a five-year term commencing    
                          January 1, 2013. Under PBR rate-making, a formula 
                          is used to determine customer rates on an annual  
                          basis. The implementation of PBR does not alter a 
                          utility's right to a reasonable opportunity to    
                          recover the prudent COS and the right to earn a   
                          reasonable ROE. The formula approved by the AUC in
                          the PBR Decision raises concerns and uncertainty  
                          for FortisAlberta regarding the treatment of      
                          certain capital expenditures. The Company will be 
                          seeking further clarification regarding those     
                          capital expenditures in the required compliance   
                          application, scheduled to be filed with the AUC in
                          November 2012. FortisAlberta has also sought leave
                          to appeal this issue with the Alberta Court of    
                          Appeal.                                           
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Newfoundland              - In March 2012 Newfoundland Power filed a Cost of
Power                     Capital 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 from  
                          customers 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 October 2012 the PUB approved Newfoundland   
                          Power's 2013 Capital Expenditure Plan totalling   
                          approximately $82 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 was primarily 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 above-noted increase in customer rates does   
                          not impact Newfoundland Power's earnings.         
                                                                            
                          - In September 2012 Newfoundland Power filed a    
                          General Rate Application for 2013 customer        
                          electricity rates and cost of capital. A hearing  
                          on the application is expected in the first       
                          quarter of 2013.                                  
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Maritime Electric         - In February 2012 the PEI Energy Commission ("PEI
                          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   
                          before the end of 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.
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FortisOntario             - In non-rebasing years, customer electricity     
                          distribution rates are set using inflationary     
                          factors less an efficiency target under the Third-
                          Generation Incentive Rate Mechanism ("IRM") as    
                          prescribed by the OEB. In the first quarter of    
                          2012, the OEB published applicable inflationary   
                          and efficiency targets, resulting in minimal      
                          changes in base customer electricity distribution 
                          rates at FortisOntario's operations in Fort Erie, 
                          Gananoque and Port Colborne effective May 1, 2012.
                          The Third-Generation IRM maintains the allowed ROE
                          at 8.01% for 2012.                                
                                                                            
                          - In April 2012 the OEB issued Final Decisions and
                          Orders for customer rates effective May 1, 2012 at
                          FortisOntario's operations in Fort Erie, Gananoque
                          and Port Colborne. The result was an average 3.1% 
                          decrease in residential customer rates in Fort    
                          Erie, an average 0.6% increase in residential     
                          customer rates in Gananoque and an average 4.6%   
                          decrease in residential customer rates in Port    
                          Colborne. The above-noted rate changes were mainly
                          due to changes in rate riders associated with     
                          regulatory deferral accounts and smart meter      
                          funding.                                          
                                                                            
                          - In April 2011 FortisOntario provided the City of
                          Port Colborne and Port Colborne Hydro with an     
                          irrevocable written notice of FortisOntario's     
                          election to exercise the purchase option, under   
                          the then-current operating lease agreement, at the
                          purchase option price of approximately $7 million 
                          on April 15, 2012. The purchase constituted 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 distribu
tion 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%. The allowed ROE is subject to change based
                          on operation of the automatic ROE adjustment      
                          formula. In September 2012 a settlement agreement 
                          on the COS Application was reached on all issues, 
                          except for the disposal of an income tax-related  
                          regulatory deferral account of $1 million, which  
                          is expected to be decided upon by the OEB by the  
                          end of 2012.                                      
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Caribbean Utilities       - In April 2012 the ERA approved Caribbean        
                          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 by  
                          the end of the 2012. A second increment of 18 MW  
                          of new generating capacity is required up to three
                          years later in 2017, contingent on economic growth
                          on Grand Cayman and the related growth in demand  
                          for electricity.                                  
                                                                            
                          - The proposed 2013-2017 CIP, totalling           
                          approximately US$125 million of non-generation    
                          installation capital expenditures, was submitted  
                          to the ERA in October 2012 for approval.          
                                                                            
                          - 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 before the end 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. During the third quarter of 2012,       
                          Caribbean Utilities commenced discussions with two
                          renewable energy developers that were selected 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 towards firm  
                          power purchase agreements with the developers are 
                          ongoing. The power purchase agreements, however,  
                          are subject to ERA review and approval. Once the  
                          negotiations are completed, and the necessary     
                          regulatory approvals received, final power        
                          purchase agreements will be established with the  
                          two developers who will then start construction of
                          the projects. It is anticipated that the 13 MW of 
                          renewable energy capacity will be connected to the
                          grid by 2014.                                     
                                                                            
                          - 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 the utility's achieved ROA for 2011.  
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Fortis Turks and Caicos   - An independent review of the regulatory         
                          framework for the electricity sector in the Turks 
                          and Caicos Islands was performed during the third 
                          quarter of 2011 on behalf of the Interim          
                          Government. 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 commenced   
                          during the third quarter of 2012 with Fortis Turks
                          and Caicos presenting a new regulatory framework  
                          proposal to the Interim Government. A third-party 
                          consultant was engaged by the Interim Government  
                          to review the proposal and provide                
                          recommendations.                                  
                                                                            
                          - 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 licences issued for the expanded service  
                          territory; and (iv) the discontinuance of the     
                          government subsidization of the utility's South   
                          Caicos operations.                                
                                                                            
                          - In March 2012 Fortis Turks and Caicos submitted 
                          its 2011 annual regulatory filing outlining the   
                          Company's performance in 2011. Included in the    
                          filing were the calculations, in accordance with  
                          the utility's licence, of rate base of US$166     
                          million for 2011 and cumulative shortfall in      
                          achieving allowable profits of US$72 million as at
                          December 31, 2011.                                
                                                                            
                          - In April 2012 Fortis Turks and Caicos entered   
                          into a Streetlight Takeover Agreement with the    
                          Interim Government, whereby the responsibility for
                          the ownership, installation and maintenance of all
                          streetlights in the utility's service territory   
                          was transferred to Fortis Turks and Caicos.       
----------------------------------------------------------------------------

 
CONSOLIDATED FINANCIAL POSITION  
The following table outlines the significant changes in the
consolidated balance sheets between September 30, 2012 and December
31, 2011.  
Significant Changes in the Consolidated Balance Sheets (Unaudited)
between September 30, 2012 and December 31, 2011 


 
                                                                            
----------------------------------------------------------------------------
                Increase/                                                   
Balance Sheet   (Decrease)                                                  
Account         ($ millions)   Explanation                                  
----------------------------------------------------------------------------
Cash and cash   60             The increase was primarily due to cash on    
equivalents                    hand at the FortisBC Energy companies        
                               associated with seasonality of operations and
                               a portion of the proceeds received from an   
                               equity injection by Fortis during the second 
                               quarter of 2012, and the timing of cash      
                               payments at FortisAlberta and the Waneta     
                               Expansion Limited Partnership (the "Waneta   
                               Partnership").                               
----------------------------------------------------------------------------
Accounts        (228)          The decrease was driven by the FortisBC      
receivable                     Energy companies, mainly due to a seasonal   
                               decrease in sales and the lower commodity    
                               cost of natural gas reflected in customer    
                               rates. Accounts receivable also decreased at 
                               Newfoundland Power, due to seasonality and   
                               the timing of collections from customers and 
                               decreased at FortisAlberta, due to decreased 
                               rate riders and a change in the billing of   
                               retailers from a monthly to a weekly basis.  
----------------------------------------------------------------------------
Inventories     23             The increase was driven by the normal        
                               seasonal increase of gas in storage at the   
                               FortisBC Energy companies, partially offset  
                               by the impact of lower natural gas commodity 
                               prices.                                      
----------------------------------------------------------------------------
Regulatory      (28)           The decrease was mainly due to: (i)          
assets -                       approximately $100 million associated with   
current and                    the deferral of the change in the fair market
long-term                      value of the natural gas derivatives at the  
                               FortisBC Energy companies; (ii) the          
                               collection of approximately $44 million in   
                               AESO charges deferral at FortisAlberta; and  
                               (iii) a reduction in regulatory deferred     
                               employee future benefits costs. The decrease 
                               was partially offset by higher regulatory    
                               deferred income taxes, and an increase in the
                               deferral of various other costs, as permitted
                               by the regulators, mainly at the FortisBC    
                               regulated utilities.                         
----------------------------------------------------------------------------
Other assets    25             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 406            The increase primarily related to $737       
assets                         million invested in electricity and gas      
                               systems, partially offset by depreciation and
                               customer contributions year-to-date 2012, and
                               the impact of foreign exchange on the        
                               translation of US-dollar denominated utility 
                               capital assets.                              
----------------------------------------------------------------------------
Short-term      (62)           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        
                               seasonality of operations, partially offset  
                               by increased borrowings at Caribbean         
                               Utilities, mainly to repay maturing long-term
                               debt.                                        
----------------------------------------------------------------------------
Accounts        (135)          The decrease was mainly due to: (i) the $75  
payable and                    million change in the fair market value of   
other current                  the natural gas derivatives at the FortisBC  
liabilities                    Energy companies; (ii) lower amounts owing   
                               for purchased natural gas at the FortisBC    
                               Energy companies and purchased power at      
                               Newfoundland Power, associated with          
                               seasonality of operations; (iii) the timing  
                               of payment of property taxes and franchise   
                               fees at the FortisBC Energy companies; and   
                               (iv) 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 and     
                               timing of AESO payments for transmission     
                               costs at FortisAlberta.                      
----------------------------------------------------------------------------
Regulatory      65             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 mainly due to: (i) an increase in the    
                               Revenue Surplus Deferred Account, reflecting 
                               amounts collected in customer rates in excess
                               of the cost of providing service at FEVI     
                               year-to-date 2012; (ii) an increase in the   
                               Midstream Cost Reconciliation Account and the
                               Commodity Cost Reconciliation Account, as    
                               amounts collected in customer rates were in  
                               excess of actual midstream and commodity gas-
                               delivery costs, respectively, year-to-date   
                               2012; and (iii) the provisioning for non-ARO 
                               removal costs commencing January 1, 2012. The
                               increase was partially offset by             
                               approximately $25 million associated with the
                               deferral of the change in the fair market    
                               value of the natural gas derivatives at the  
                               FortisBC Energy companies.                   
----------------------------------------------------------------------------
Deferred income 57             The increase was driven by tax timing        
tax liabilities                differences related mainly to capital        
- current and                  expenditures at the regulated utilities.     
long-term                                                                   
----------------------------------------------------------------------------
Long-term debt  149            The increase was primarily due to higher     
 (including                    borrowings under the Corporation's committed 
current                        credit facility, largely in support of the   
portion)                       construction of the Waneta Expansion and for 
                               other general corporate purposes. The        
                               increase was partially offset by regularly   
                               scheduled debt repayments at Fortis          
                               Properties, the FortisBC Energy companies and
                               Caribbean Utilities, and the impact of       
                               foreign exchange on the translation of US-   
                               dollar denominated debt.                     
----------------------------------------------------------------------------
Shareholders'   110            The increase was primarily due to net        
equity                         earnings attributable to common equity       
 (before non-                  shareholders year-to-date 2012, less common  
controlling                    share dividends, and the issuance of common  
interests)                     shares mainly under the Corporation's        
                               dividend reinvestment and stock option plans.
----------------------------------------------------------------------------
Non-controlling 80             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.                            
----------------------------------------------------------------------------

 
LIQUIDITY AND CAPITAL RESOURCES 
The table below outlines the Corporation's consolidated sources and
uses of cash for the third quarter and year-to-date 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                                                               
 September 30                           Quarter                Year-to-Date 
($ millions)            2012     2011  Variance     2012     2011  Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, Beginning of                                                          
 Period                  231      296       (65)      87      107       (20)
Cash Provided by                                                            
 (Used in):                                                                 
  Operating                                                                 
   Activities            221      151        70      804      684       120 
  Investing                                                                 
   Activities           (277)    (265)      (12)    (761)    (748)      (13)
  Financing                                                                 
   Activities            (28)     (77)       49       17       62       (45)
  Effect of Exchange                                                        
   Rate Changes on                                                          
   Cash and Cash                                                            
   Equivalents             -        1        (1)       -        1        (1)
----------------------------------------------------------------------------
Cash, End of Period      147      106        41      147      106        41 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Operating Activities:  Cash flow from operating activities was $70
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 expense, mainly at the FortisBC Energy companies; and
(iii) favourable changes in long-term regulatory deferral accounts.
The favourable changes in working capital were associated with
changes in inventories, accounts payable and other current
liabilities, and current regulatory deferral accounts, partially
offset by unfavourable changes in accounts receivable. The increase
was partially offset by lower earnings. 
Cash flow from operating activities was $120 million higher year to
date compared to the same period last year. The increase was
primarily due to favourable changes in working capital and the
collection from customers of regulator-approved increased
depreciation and amortization expense, mainly at the FortisBC Energy
companies. Favourable changes in working capital were associated with
changes in current regulatory deferral accounts and accounts
receivable. The above increase was partially offset by unfavourable
changes in long-term regulatory deferral accounts and a defined
benefit pension solvency deficit funding payment made by Newfoundland
Power during the second quarter of 2012. 
Investing Activities: Cash used in investing activities was $12
million higher for the quarter and $13 million higher year to date.
The increases reflected the acquisition of TCU in August 2012 for a
net cash purchase price of approximately $7 million (US$7 million),
net of cash acquired. The increase year to date also reflected the
acquisition of the remaining assets of Port Colborne Hydro by
FortisOntario in April 2012 for approximately $7 million. 
For the quarter, lower capital spending related to the non-regulated
Waneta Expansion and at FortisBC Electric and the Caribbean Regulated
Electric Utilities was largely offset by an increase in capital
spending at FortisAlberta. Year to date, lower capital spending at
the FortisBC Energy companies and FortisBC Electric was largely
offset by an increase in capital spending at FortisAlberta and
capital spending related to the non-regulated Waneta Expansion.
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 GOB. 
Financing Activities: Cash used in financing activities was $49
million lower quarter over quarter. The decrease was primarily due to
lower net repayments under committed credit facilities classified as
long term, partially offset by lower net proceeds from short-term
borrowings and lower proceeds from the issuance of common shares.  
Cash provided by financing activities was $45 million lower year to
date compared to the same period last year. The decrease was
primarily due to: (i) lower proceeds from the issuance of common
shares; (ii) lower proceeds from long-term debt; (iii) higher
repayments of long-term debt; (iv) higher common share dividends
paid; and (v) issue costs related to the June 2012 Subscription
Receipts offering. The decrease was partially offset by higher net
borrowings under committed credit facilities classified as long term
and lower net repayments of short-term borrowings. 
Net proceeds from short-term borrowings were $69 million lower
quarter over quarter, driven by the FortisBC Energy companies. Net
repayments of short-term borrowings were $53 million lower year to
date compared to same period last year, driven by Caribbean
Utilities. 
Proceeds from long-term debt, net of issue costs, repayments of
long-term debt and capital lease and finance obligations, and net
(repayments) borrowings under committed credit facilities for the
quarter and year to date compared to the same periods last year are
summarized in the following tables. 


 
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)                
Periods Ended                                                               
 September 30                           Quarter                Year-to-Date 
($ millions)             2012     2011 Variance      2012     2011 Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caribbean Utilities                                                         
 (1)                        -        9       (9)        -       38      (38)
Other                       -        -        -         -        1       (1)
----------------------------------------------------------------------------
Total                       -        9       (9)        -       39      (39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Issued 15-year US$15 million 4.85% and 20-year US$25 million 5.10%    
    unsecured notes. The first tranche of US$30 million was issued in June
    2011 and the second tranche of US$10 million was issued in July 2011. 
    The net proceeds were used to repay current installments on long-term 
    debt and short-term credit facility borrowings and to finance capital 
    expenditures.                                                         
                                                                          
                                                                          
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations      
 (Unaudited)                                                                
Periods Ended                                                               
 September 30                            Quarter               Year-to-Date 
($ millions)              2012    2011  Variance    2012     2011  Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisBC Energy                                                             
 Companies                   -      (1)        1     (18)      (3)      (15)
Caribbean Utilities          -       -         -     (13)     (12)       (1)
Fortis Properties            -      (2)        2     (24)      (6)      (18)
Other                        -       -         -      (2)      (6)        4 
----------------------------------------------------------------------------
Total                        -      (3)        3     (57)     (27)      (30)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
 

 
----------------------------------------------------------------------------
Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)   
Periods Ended                                                               
 September 30                           Quarter                Year-to-Date 
($ millions)             2012     2011 Variance     2012     2011  Variance 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
FortisAlberta             (22)      33      (55)     (13)      50       (63)
FortisBC Electric         (17)      (7)     (10)      (9)       -        (9)
Newfoundland Power        (20)     (13)      (7)       8       10        (2)
Corporate                  50     (191)     241      235     (165)      400 
----------------------------------------------------------------------------
Total                      (9)    (178)     169      221     (105)      326 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Borrowings under credit facilities by the utilities are primarily in
support of their capital expenditure programs and/or for working
capital requirements. Repayments are primarily financed through the
issuance of long-term debt, cash from operations and/or equity
injections from Fortis. From time to time, proceeds from preference
share, common share and long-term debt offerings are used to repay
borrowings under the Corporation's committed credit facility. The
borrowings under the Corporation's committed credit facility during
2012 were largely in support of the construction of the Waneta
Expansion and for other general corporate purposes.  
Advances of approximately $14 million for the quarter and $70 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 $20 million received for the third quarter of
2011 and $76 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 publicly issued 9.1 million common shares for
gross proceeds of $300 million. In July 2011 an additional 1.2
million common shares were publicly issued upon the exercise of an
over-allotment option, resulting in gross proceeds of approximately
$41 million. The total net proceeds of $327 million from the common
share offering were used to repay borrowings under credit facilities
and finance equity injections into the regulated utilities in western
Canada and the Waneta Partnership in support of infrastructure
investment, and for other general corporate purposes. 
Common share dividends paid during the third quarter of 2012 were $42
million, net of $15 million of dividends reinvested, compared to $38
million, net of $16 million of dividends reinvested, paid during the
same quarter of 2011. Common share dividends paid year-to-date 2012
were $128 million, net of $43 million of dividends reinvested,
compared to $109 million, net of $47 million of dividends reinvested,
paid year-to-date 2011. The dividend paid per common share for each
of the first, second and third quarters of 2012 was $0.30 compared to
$0.29 for each of the first, second and third quarters of 2011. The
weighted average number of common shares outstanding for the third
quarter and year to date was 190.2 million and 189.6 million,
respectively, compared to 186.5 million and 179.5 million for the
third quarter and year to date, respectively, in 2011. 
CONTRACTUAL OBLIGATIONS 
As at September 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 September 30, 2012                      within   years   years   after
($ millions)                           Total  1 year 2 and 3 4 and 5 5 years
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt                         5,937      90     826     563   4,458
Capital lease and finance                                                   
 obligations (1)                       2,605      47      97     101   2,360
Waneta Partnership promissory note        72       -       -       -      72
Gas purchase contract obligations                                           
 (2)                                     351     289      62       -       -
Power purchase obligations                                                  
  FortisBC Electric                       20      11       6       3       -
  FortisOntario                          371      44      99     105     123
  Maritime Electric                      148      37      80      18      13
Capital cost                             446      17      36      35     358
Joint-use asset and shared service                                          
 agreements                               63       4       8       6      45
Operating lease obligations               26       4       7       6       9
Defined benefit pension funding                                             
 contributions (3)                        88      37      34      15       2
Other                                      8       1       3       -       4
----------------------------------------------------------------------------
Total                                 10,135     581   1,258     852   7,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 September 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, 2013  FortisAlberta                                      
    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 as follows. 
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.  
In September 2012 Caribbean Utilities entered into primary and
secondary fuel supply contracts with two different suppliers and is
committed to purchasing approximately 60% and 40% of the Company's
diesel fuel requirements under each of the contracts, respectively,
for the operation of Caribbean Utilities' diesel-powered generating
plant. The approximate combined quantities under the contracts,
expressed in millions of imperial gallons, on an annual basis by
fiscal year are: 2012 - 10.8, 2013 - 32.4 and 2014 - 18.9. The
contracts expire in July 2014 with the option to renew for two
additional 18-month terms. The renewal options can be exercised only
within six months of the expiry dates of the existing contracts.  
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,
realizing 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
"Significant Items" and "Business Risk Management" sections of this
MD&A.  
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets for approximately $55 million. Closing of
the transaction is subject to certain conditions and approvals. For
further information, refer to the "Significant Items" 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 preceeding Contractual Obligations table, refer to the "Capital
Expenditure Program" section of this MD&A. 
CAPITAL STRUCTURE 
The Corporation's principal businesses of regulated gas and
electricity distribution require ongoing access to capital to enable
the utilities to fund maintenance and expansion of infrastructure.
Fortis raises debt at the subsidiary level to ensure regulatory
transparency, tax efficiency and financing flexibility. Fortis
generally finances a significant portion of acquisitions at the
corporate level with proceeds from common share, preference share and
long-term debt offerings. To help ensure access to capital, the
Corporation targets a consolidated long-term capital structure
containing approximately 40% equity, including preference shares, and
60% debt, as well as investment-grade credit ratings. Each of the
Corporation's regulated utilities maintains its own capital structure
in line with the deemed capital structure reflected in each of the
utility's customer rates.  
The consolidated capital structure of Fortis is presented in the
following table. 


 
----------------------------------------------------------------------------
Capital Structure                                                           
 (Unaudited)                                      As at                     
                                  September 30, 2012       December 31, 2011
                            ($ millions)         (%)($ millions)         (%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt and capital lease                                                
 and finance obligations                                                    
 (net of cash) (1) (2)             6,328        56.6       6,296        57.1
Preference shares                    912         8.2         912         8.3
Common shareholders' equity        3,933        35.2       3,823        34.6
----------------------------------------------------------------------------
Total (3)                         11,173       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 54.9% as at September 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)
lower short-term borrowings; (ii) an increase in cash; (iii) common
shares issued, mainly under the Corporation's dividend reinvestment
and stock option plans; and (iv) net earnings attributable to common
equity shareholders, net of dividends. 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, largely
in support of the construction of the Waneta Expansion and for other
general corporate purposes, 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. Due to 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, S&P and
DBRS also 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. 
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 $794 million in gross capital expenditures by
segment year-to-date 2012 is provided in the following table. 


 
----------------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)                     
Year-to-Date September 30, 2012                                             
($ millions)                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                               Other                                        
                              Regula-  Total  Regula-                       
                                 ted   Regula    ted                        
                                Elec-       -   Elec-   Non-                
Fortis                          tric      ted   tric  Regula-               
BC              Fortis   New-  Utili-  Utili-  Utili-  ted -                
Energy Fortis      BC  found-  ties - ties -   ties -  Utili- Fortis        
Compa- Alberta   Elec-   land   Cana-   Cana-  Carib-      ty Proper-       
nies       (2)    tric  Power    dian    dian    bean     (3)    ties Total 
----------------------------------------------------------------------------
144      304       52     58      35     593      33    144       24    794 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 depreciation and amortization and non-cash equity         
    component of AFUDC.                                                   
                                                                          
(2) Includes payments made to AESO for investment in transmission-related 
    capital projects                                                      
                                                                          
(3) Includes non-regulated generation capital expenditures, mainly related
    to the Waneta Expansion                                               

 
Planned capital expenditures are based on detailed forecasts of
energy demand, weather, cost of labour and materials, as well as
other factors, including economic conditions, which could change and
cause actual expenditures to differ from forecasts.  
There have been no material changes in the overall expected level,
nature and timing of the Corporation's significant capital projects
from those that were disclosed in the 2011 Annual MD&A. Gross
consolidated capital expenditures for 2012 are forecasted at
approximately $1.3 billion. 
FEI's Customer Care Enhancement Project, at an estimated total
project cost of $110 million, came into service at the beginning of
January 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
$380 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 64% of the $5.5 billion capital program
is expected to be incurred at the regulated electric utilities,
driven by FortisAlberta and FortisBC Electric. Approximately 23% and
13% 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 September 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 "Significant Items" and "Business Risk
Management" sections 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
September 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 nine months ended
September 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 September 30, 2012 and are expected to remain compliant throughout
the remainder of 2012. 
CREDIT FACILITIES 
As at September 30, 2012, the Corporation and its subsidiaries had
consolidated credit facilities of approximately $2.5 billion, of
which $2.0 billion was unused, including $764 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. 


 
----------------------------------------------------------------------------
Credit Facilities (Unaudited)                                         As at 
                                                        September  December 
                       Regulated      Fortis  Corporate       30,       31, 
($ millions)           Utilities  Properties  and Other      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total credit facilities    1,401          13      1,045     2,459     2,248 
Credit facilities                                                           
 utilized:                                                                  
  Short-term borrowings      (97)          -          -       (97)     (159)
  Long-term debt                                                            
   (including current                                                       
   portion)                  (63)          -       (236)     (299)      (74)
Letters of credit                                                           
 outstanding                 (67)          -         (1)      (68)      (66)
----------------------------------------------------------------------------
Credit facilities                                                           
 unused                    1,174          13        808     1,995     1,949 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
As at September 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 from August 2015 to August
2017. 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 unsecured 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, extending the
maturity date from August 2013 to August 2014. The amended credit
facility 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 from September 2015 to August 2016.
The amended credit facility agreement reflects a decrease in pricing
but, 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. 


 
----------------------------------------------------------------------------
Financial Instruments                                                       
 (Unaudited)                                      As at                     
                                  September 30, 2012       December 31, 2011
                                Carrying   Estimated    Carrying   Estimated
($ millions)                       Value  Fair Value       Value  Fair Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Waneta Partnership                                                          
 promissory note                      46          52          45          49
Long-term debt, including                                                   
 current portion                   5,937       7,476       5,788       7,172
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 expropriated investment in
Belize Electricity. 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
appropriate fair value 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 totalled approximately $103 million as at September
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-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 ("BECOL") is the US dollar. Belize
Electricity's financial results were denominated in Belizean dollars,
which are pegged to the US dollar.  
As at September 30, 2012, the Corporation's corporately issued US$557
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 September 30, 2012, the Corporation had
approximately US$19 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
expropriated investment in Belize Electricity does not qualify for
hedge accounting as Belize Electricity is no longer a foreign
subsidiary of Fortis. As a result, 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 long-term other 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. The Corporation has recognized in earnings
foreign exchange losses of approximately $3 million and $2.5 million
during the three and nine months ended September 30, 2012,
respectively. During the third quarter of 2011, a foreign exchange
gain of $7 million associated with the translation of the above-noted
US dollar-denominated long-term other asset was partially offset by a
$5.5 million ($4.5 million after tax) foreign exchange loss
associated with the translation of previously hedged US
dollar-denominated long-term debt, resulting in a net foreign
exchange gain of approximately $2.5 million after tax. 
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 September 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. 


 
----------------------------------------------------------------------------
Derivative Financial Instruments (Unaudited)                 As at          
                                                      September    December 
                                                            30,         31, 
                                                           2012        2011 
                                                       Carrying    Carrying 
                                                      Value (2)   Value (2) 
                                Number of                    ($          ($ 
(Liability) Asset    Maturity   Contracts Volume (1)  millions)   millions) 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign exchange                                                            
 forward contract    2012 (3)           -          -          -           - 
Fuel option                                                                 
 contracts           2013 (4)           4          7          -          (1)
Natural gas                                                                 
 derivatives:                                                               
  Gas swaps and                                                             
   options               2014          99         36        (60)       (135)
  Gas purchase                                                              
   contract                                                                 
   premiums              2014          80        112          1           - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)  The volume for fuel option contracts is reported in millions of        
     imperial gallons and for natural gas derivatives is reported in PJ.    
                                                                            
(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.                                                     
                                                                            
(4)  The carrying value of the fuel option contracts was less than $1       
     million as at September 30, 2012.                                      

 
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. In October 2012 Caribbean Utilities executed
additional fuel option contracts covering the period from November 1,
2012 to October 31, 2013. With the execution of these new contracts,
approximately 70% of the Company's annual diesel fuel requirements
are under fuel hedging arrangements.  
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 and other
current liabilities as at September 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 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.  
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 September 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
year-to-date 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
2012-2013 revenue requirements at the FortisBC Energy companies and
for 2012 distribution revenue requirements at FortisAlberta.
Similarly, a decision was received in August 2012 for 2012-2013
revenue requirements at FortisBC Electric. The receipt of two-year
revenue requirements decisions at the FortisBC utilities helps to
provide a level of operating stability for 2012 and 2013. 
The recent decision by the AUC to transition distribution utilities
in Alberta to PBR for a five-year period commencing in 2013 is a
fundamental change in how these utilities are regulated; however, the
change provides an opportunity for reduced regulatory burden and the
incentive to achieve greater efficiencies and cost savings, which can
lead to improved earnings. Under PBR, there is greater risk that
FortisAlberta's earnings will be negatively impacted given the length
of the PBR term and the uncertainty of resulting rate adjustments. It
is possible that the approved PBR formula could have an unfavourable
impact on FortisAlberta if the utility's actual costs, including
costs associated with certain of its required capital projects,
exceed the costs permitted by the PBR formula. In the absence of
clarification by the AUC, which would broaden the scope of the
recovery of these costs, the PBR formula conflicts with
FortisAlberta's legal right to recover prudent costs of providing
distribution services and to earn a reasonable ROE. FortisAlberta
will be seeking further clarification regarding the application of
the PBR formula in proceedings before the AUC and has sought leave to
appeal the PBR Decision with the Alberta Court of Appeal. 
The regulatory calendar, particularly at the FortisBC utilities, will
be busy to the end of 2012 and into 2013 with various filings,
interrogatories, inquiries and/or hearings occurring, including that
related to the GCOC Proceeding and an expected request for approval
of FortisBC Electric's proposed acquisition of the City of Kelowna's
electrical utility assets. Determinations of cost of capital and
final allowed ROEs for 2013 for FortisAlberta and Newfoundland Power
also remain outstanding. The results of cost of capital proceedings
could materially impact the earnings of the Corporation's largest
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 remains subject to NYSPSC approval. A delay in
receiving the approval, and/or conditions imposed, if any, under such
approval, may result in the failure to materialize some, or all, of
the expected benefits of the acquisition of CH Energy Group or such
benefits may not occur within the time periods anticipated by the
Corporation. The realization of such benefits may also be impacted by
other factors beyond the control of Fortis.  
The agreement and plan of merger may be terminated by the Corporation
or CH Energy Group at any time prior to closing in certain
circumstances, including if the acquisition has not closed by
February 20, 2013 provided, however, that if the only unsatisfied
conditions to closing are the obtaining of the regulatory approvals
as defined in the agreement and plan of merger, then such date shall
be extended to August 20, 2013.  
A portion of the acquisition purchase price is expected to be funded
by $601 million of escrowed proceeds from the Corporation's June 2012
Subscription Receipts offering. If conditions precedent to the
closing of the transaction are not fulfilled or waived, including
receipt of NYSPSC approval, by June 30, 2013, or if the agreement and
plan of merger related to the acquisition is terminated prior to such
time, the proceeds from the Subscription Receipts offering, plus pro
rata interest earned, are required to be returned to the holders of
such receipts. As a result, closing of the transaction subsequent to
June 30, 2013 could result in the Corporation having to raise
alternative capital to finance the acquisition. 
For further information refer to the "Significant Items" section of
this MD&A. 
Expropriation of Shares in Belize Electricity: In 2008 the newly
elected GOB changed the electricity rate-setting methodology in
Belize to one that did not allow Belize Electricity to recover its
reasonable COS and make a reasonable rate of return on its investment
as required by law and, thereby, it is the Corporation's position
that the GOB has breached covenants that the GOB made when it sold
its shares in Belize Electricity to Fortis in 1999. Relying on the
new rate-setting methodology, the Belize Public Utilities Commission
denied Belize Electricity a customer rate increase in its June 2008
Final Decision and subsequently amended that decision to decrease
customer rates by 15%, notwithstanding the fact that a rate increase
was required to adequately finance the utility's operations. The GOB
further compounded Belize Electricity's financial problems when it
increased the utility's business tax from 1.75% to 6.5%, effective in
2010. Due to an increase in the cost of purchased power, higher
business taxes and the above-noted denial of compensatory customer
rates, Belize Electricity required short-term financial assistance
from the GOB in spring 2011. The GOB chose to prepay some of its
electricity bills, as the preferred alternative of financial
assistance from the options proposed by Belize Electricity, which
allowed the utility to meet its power purchase obligations with the
Mexican state-owned Comision Federal de Electricidad ("CFE") to the
end of June 2011, after which time Belize Electricity would have been
able to source most of its energy power requirements from lower-cost
local hydroelectric generating facilities, rather than from the CFE,
coinciding with the commencement of the rainy season in Belize.  
On June 20, 2011, the GOB enacted in one day the Electricity
(Amendment) Act 2011 ("Acquisition Act") and the Electricity
(Assumption of Control over Belize Electricity Limited) Order 2011
("Acquisition Order"), to expropriate the Corporation's majority
ownership investment in Belize Electricity but did not expropriate
any of the minority ownership investments, which continue to be held
by the Social Security Board of Belize and Belizean residents. The
purported public purpose stated in the Acquisition Order, as the
basis of the decision to expropriate Belize Electricity, was "to
maintain an uninterrupted and reliable supply of electricity to the
public". The Corporation's evidence is that there was no risk of
interruption or unreliable electricity supply at the time of
expropriation and, while Belize Electricity had financial
difficulties in 2011, such difficulties were caused by the GOB and,
therefore, the GOB cannot rely on a situation it created to justify
expropriating Belize Electricity.  
Four days after expropriation of the Corporation's investment in
Belize Electricity, the Belize Court of Appeal delivered its judgment
that a similar expropriation of control of Belize Telemedia Limited
("Belize Telemedia"), a public telecommunications provider in Belize,
in 2009 was unconstitutional, null and void. Rather than accept and
appeal the judgment, the GOB enacted revised expropriation
legislation to retain control of Belize Telemedia and
contemporaneously proposed a constitutional amendment, the purported
effect of which was to: (i) declare the GOB ownership of three
specifically identified public utility providers, including Belize
Electricity and Belize Telemedia; (ii) deem the expropriation of
Belize Electricity and re-expropriation of Belize Telemedia to have
been done for a public purpose; and (iii) oust the jurisdiction of
the Belize Courts to review the GOB expropriation actions. 
On October 21, 2011, Fortis filed a claim ("Claim No. 673 of 2011")
in the Belize Supreme Court challenging the GOB's expropriation of
the Corporation's investment in Belize Electricity pursuant to the
Acquisition Act and Acquisition Order. On October 25, 2011, the
Belize Constitution (Eighth Amendment) Act 2011 ("Eighth Amendment")
was enacted to validate and immunize the GOB's expropriation of
Belize Electricity and Belize Telemedia. As a consequence of the
above, Fortis subsequently amended its Claim No. 673 of 2011 to
additionally challenge the constitutionality of the Eighth Amendment. 
On June 11, 2012, the trial division of the Belize Supreme Court
delivered its judgment in the claims of British Caribbean Bank
Limited v Attorney General et al ("Claim No. 597 of 2011") and Dean
Boyce v Attorney General et al ("Claim No. 646 of 2011")
(collectively the "Telemedia Judgment") regarding the purported
re-expropriation of Belize Telemedia. The court determined that the
re-expropriation of the Claimants' properties by the GOB in those
claims was unconstitutional, null and void. The judge determined most
of the Eighth Amendment to be invalid, but found that he could sever
those portions of sections 143 and 144 which declare GOB ownership of
the named utilities, and that the severance thereby prevented the
judge from ordering divestiture of the GOB's control of Belize
Telemedia and hence the judge found himself precluded by the Belize
Constitution from granting the Claimants the consequential relief
sought. 
Hearing of the Corporation's Claim No. 673 of 2011 occurred on July
2, 2012 before the same judge who delivered the Telemedia Judgment.
The judge believed he was bound by his reasons in the Telemedia
Judgment and dismissed the Corporation's Claim No. 673 of 2011 on the
grounds that the severed portions of the Eighth Amendment precluded
divestiture of the GOB ownership and control of Belize Electricity,
notwithstanding the Acquisition Act and Acquisition Order, which are
virtually identical to the provisions of the 2009 expropriation of
Belize Telemedia, and were found to be invalid by the Belize Court of
Appeal. The judge, therefore, denied the relief sought by Fortis. 
On July 5, 2012, Fortis filed its appeal of the above-noted July 2,
2012 trial judgment to the Belize Court of Appeal. The Belize Court
of Appeal allowed an application for consolidation of the
Corporation's appeal with the appeal and cross-appeal of the
Telemedia Judgment, and directed that the appeals be heard on an
expedited basis commencing October 8, 2012.  
In its appeal, Fortis has submitted that the Acquisition Act violates
the Belize Constitution and should be struck down as: (i) the
Acquisition Act does not prescribe the principles and manner in which
reasonable compensation is to be determined in a reasonable time;
(ii) the Acquisition Act does not prescribe the principles and manner
in which reasonable compensation is to be given in a reasonable time;
(iii) the Acquisition Act does not provide a right of access to the
Belize Court for the purpose of enforcing a right to compensation;
and (iv) certain sections of the Acquisition Act violate certain
sections of the Belize Constitution. Fortis also submitted that the
Acquisition Order violates the Corporation's constitutional rights
and should be struck down as: (i) it is not proportionate; (ii) the
expropriation of Belize Electricity by the GOB was arbitrary as the
GOB did not acquire the minority shareholdings of the Social Security
Board or Belizean nationals in Belize Electricity and is, therefore,
in violation of the Belize Constitution; and (iii) Fortis was not
afforded a right to be heard by the Belize Minister of Public
Utilities before its property was compulsorily acquired by the GOB.
Fortis also contends that the application of saved portions of
sections 143 and 144 of the Eighth Amendment are also invalid and
should not have precluded the ordering of consequential relief to
Fortis for several reasons, including that fact that such provisions
are void as they: (i) deprive the Belize Court of jurisdiction to
conduct the constitutionally mandated inquiry to determine a person's
interest or right in property compulsorily acquired, whether such
acquisition was for a public purpose, the amount of compensation to
which a person is entitled and for enforcement of a person's right to
any such compensation; (ii) are in breach of the principle of
equality before the law and the rule of law; and (iii) on their own
do not fulfill the intention of the legislature of the Belize
Government and are inextricably bound up with the legislation ruled
to be unconstitutional in the Telemedia Judgment. 
The consolidated appeal hearing occurred from October 8 to October
10, 2012. However, since one of the judges on the panel is the
subject of a complaint to the Belize Judicial Council by parties to
the Telemedia Judgment, an application for disqualification of that
judge was made and subsequently denied by a majority of the appeal
panel. Reasons for denial of leave to appeal of the disqualification
application was delivered and judgment on the consolidated appeal
hearing has been suspended, pending the outcome of the appeal in the
Caribbean Court of Justice ("CCJ") relating to the disqualification
application. Counsel for the GOB admitted during the consolidated
appeal hearing that the Acquisition Act and Acquisition Order were
contrary to the laws of Belize as it now stands, on the basis of the
Belize Court of Appeal decision regarding the 2009 expropriation of
Belize Telemedia, but that the severed provisions of the Eighth
Amendment preclude return of majority control over Belize Electricity
back to Fortis. A possible outcome of the consolidated appeal could
be the return to Fortis of the majority ownership interest in Belize
Electricity. Alternatively, in the event that the Belize Court of
Appeal decision confirms the trial judgment, Fortis could pursue an
appeal of the case to the CCJ, the highest court of appeal available
for judicial matters in Belize.  
Consequent to the deprivation of control over the operations of
Belize Electricity, the Corporation discontinued the consolidation
method of accounting for the utility, effective June 20, 2011. The
Corporation has classified the book value of the expropriated
investment in Belize Electricity as a long-term other asset on the
consolidated balance sheet. As at September 30, 2012, the long-term
other asset, including foreign exchange impacts, totalled $103
million (December 31, 2011 - $106 million; September 30, 2011 - $103
million). 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 book value of the
long-term other asset is below fair value as at the date of
expropriation as determined under the Corporation's valuation. 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 both the fair value determined under the Corporation's
valuation and the book value of the long-term other asset. While
Fortis and representatives and third-party consultants of the GOB
have held discussions in 2012 on differences in assumptions used in
the valuations, there have been no discussions on any compensation
settlement amount.  
Fortis believes it has a strong, well-positioned case before the
Belize Courts and will continue to vigorously litigate the legality
of the expropriation. There exists, however, a reasonable possibility
that the outcome of the above-noted litigation may be unfavourable to
the Corporation and the amount of compensation to be paid to Fortis
could be lower than the book value of its expropriated investment in
Belize Electricity. Based on presently available information, the
outcome of the above is not determinable at this time. As such, the
long-term other asset is not deemed impaired. Fortis will continue to
assess for impairment each reporting period based on the outcomes of
court proceedings and/or compensation settlement negotiations, if
any. As well as continuing its legal actions, Fortis is also pursuing
alternative options for obtaining fair compensation.  
Fortis continues to control and consolidate the financial statements
of BECOL, the Corporation's indirect wholly owned non-regulated
hydroelectric generating subsidiary in Belize. As at October 31,
2012, Belize Electricity owed BECOL US$10 million for overdue energy
purchases representing over 40% of BECOL's annual sales to Belize
Electricity. In accordance with long-standing agreements, the GOB
guarantees the payment of Belize Electricity's obligations to BECOL. 
Capital Resources and Liquidity Risk - Credit Ratings: In May 2012
and July 2012, S&P and DBRS, respectively, affirmed the Corporation's
debt credit ratings. Due to 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, S&P and DBRS also 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. 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 September 30, 2012, the
fair value of the Corporation's consolidated defined benefit pension
plan assets was $850 million, up $65 million or 8.3%, 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 collective agreement
expiring in March 2014 was reached with regard to certain customer
service employees who were previously covered under the expired
contract. A tentative agreement has been reached with regard to the
remaining support and technical employees. The tentative agreement
expires on December 31, 2013 and is subject to ratification by the
affected 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 STANDARDS AND POLICIES 
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 with the restatement
of comparative reporting periods. 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 on SEDAR. 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. 
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 RRA and subsequently approved by the regulator in its April
2012 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 forecasted 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 nine months ended September 30, 2012, non-ARO
removal costs of $5 million and $15 million, respectively, were
accrued as a part of depreciation expense. For the three and nine
months ended September 30, 2011, non-ARO removal costs of
approximately $4 million and $12 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. As applied for in FortisBC Electric's 2012-2013
RRA and approved by the BCUC, prospectively from January 1, 2012 the
above-noted sharing of positive or negative variances is no longer in
effect. Beginning in 2012, variances between actual electricity
revenue and purchased power 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, do not impact net earnings in 2012. Effective
January 1, 2012, however, the flow through treatment for finance
charges, as was applied for in FortisBC Electric's 2012-2013 RRA, was
denied by the regulator pursuant to its revenue requirements
decision. As a result, a retroactive adjustment was recorded in the
third quarter of 2012 to eliminate the flow through treatment.
Variances between actual finance charges from those forecasted in
determining customer electricity rates, therefore, have an impact on
net earnings in 2012. 
Effective January 1, 2012, as approved by the regulator, the FortisBC
Energy companies are deferring variances between actual depreciation
expense and that forecasted in determining customer gas rates. 
Effective January 1, 2012, as approved by the regulator,
FortisAlberta is no longer permitted to defer transmission volume
variances associated with its AESO charges deferral account. For the
three and nine months ended September 30, 2012, FortisAlberta
recognized approximately $3.5 million and $6.5 million, respectively,
of net transmission revenue as a result of this change. 
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 as of
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 interim unaudited consolidated financial statements
for the three and nine months ended September 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. Similarly, FortisBC Electric recorded the cumulative
impacts of its revenue requirements decision, effective January 1,
2012, in the third quarter of 2012 when the decision was received.
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 year-to-date 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 and FortisBC Electric, in conjunction with approved
depreciation studies and revenue requirements decisions received in
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. FortisBC Electric's
composite depreciation rate for utility capital assets decreased to
3.1% for 2012 from 3.2% 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 Standards and 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. 
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
is appealing these 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 filed a statement of defence. During the second
quarter of 2010, FHI was added as a third party in all of the related
actions. FHI was advised that all matters have now been settled and
the action has been dismissed by consent. 
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 December 31, 2010 through September
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.  


 
----------------------------------------------------------------------------
Summary of Quarterly Results                                                
(Unaudited)                                                                 
                                      Net Earnings                          
                                      Attributable                          
                                                to                          
                                     Common Equity                          
                              Revenue Shareholders Earnings per Common Share
Quarter Ended            ($ millions) ($ millions)    Basic ($)  Diluted ($)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, 2012                714           45         0.24         0.24
June 30, 2012                     792           62         0.33         0.33
March 31, 2012                  1,149          121         0.64         0.62
December 31, 2011               1,034           82         0.44         0.43
September 30, 2011                699           56         0.30         0.30
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
A summary of the past eight quarters reflects the Corporation's
continued organic growth, growth from acquisitions, as well as the
seasonality associated with its businesses. Interim results will
fluctuate due to the seasonal nature of gas and electricity demand
and water flows, as well as the timing and recognition of regulatory
decisions. 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, second and third
quarters of 2012 were reduced by approximately $4 million, $3 million
and $0.5 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. Similarly, FortisBC Electric recorded the cumulative
impacts of its rate decision, effective January 1, 2012, in the third
quarter of 2012 when the decision was received. Financial results
from the fourth quarter ended December 31, 2011 reflected the
acquisition of the Hilton Suites 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 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 GOB. For further information, refer to the
"Significant Items" and "Business Risk Management" sections of this
MD&A.  
September 2012/September 2011: Net earnings attributable to common
equity shareholders were $45 million, or $0.24 per common share, for
the third quarter of 2012 compared to earnings of $56 million, or
$0.30 per common share, for the third quarter of 2011. A discussion
of the quarter over quarter variance in financial results is provided
in the "Financial Highlights" section of this MD&A. 
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. The increase in
earnings was mainly due to higher contribution from FortisAlberta,
increased non-regulated hydroelectric production in Belize,
associated with higher rainfall, and higher earnings at Newfoundland
Power, partially offset by higher corporate expenses and decreased
earnings at the FortisBC Energy companies. Higher contribution from
FortisAlberta related to rate base growth, and increased net
transmission revenue and reduced depreciation as approved by the
regulator, partially offset by a lower allowed ROE. Higher earnings
at Newfoundland Power were the result of lower effective income taxes
and a higher allowed ROE. The cumulative impact of the increase in
the regulator-approved allowed ROE, effective January 1, 2012, was
recorded in the second quarter of 2012. The increase in corporate
expenses was 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 foreign exchange gain of
approximately $2 million recognized in the second quarter of 2012.
Decreased earnings at the FortisBC Energy companies mainly related to
lower-than-expected customer additions in 2012 and lower capitalized
AFUDC, partially offset by higher gas transportation volumes to
industrial customers. A 7% 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 second quarter of 2012. 
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 favourable impact of the difference in the
timing of recognition of revenue associated with seasonal gas
consumption and certain increased regulator-approved expenses in
2012, rate base growth and higher gas transportation volumes to
industrial customers, partially offset by lower-than-expected
customer additions in 2012 and lower capitalized AFUDC. The increase
in corporate expenses was the result of approximately $4 million ($4
million after tax) 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, 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 industrial customers,
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 quart
er 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 year-to-date 2012, other than the above-noted change, there were
no changes in the Corporation's internal controls over financial
reporting that have materially, or are 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. CH Energy Group is expected to add approximately $0.5
billion to the Corporation's consolidated capital expenditure program
from 2013 through 2016.  
Fortis is focused on closing the CH Energy Group transaction by the
end of the first quarter of 2013. Approval of the transaction by the
NYSPSC is the one remaining significant regulatory matter. 
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.  
SUBSEQUENT EVENT 
In October 2012 FortisAlberta issued 40-year $125 million 3.98%
senior unsecured debentures, the proceeds of which are being used to
repay borrowings under the Company's credit facility, fund future
capital expenditures, and for general corporate purposes.  
OUTSTANDING SHARE DATA 
As at October 31, 2012, the Corporation had issued and outstanding
approximately 190.7 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 regular voting rights. The
Corporation's First Preference Shares do not have voting rights
unless and until Fortis fails to pay eight quarterly dividends,
whether or not consecutive and whether or not such dividends have
been declared. 
The number of common shares of Fortis that would be issued if all
outstanding stock options, First Preference Shares, Series C and E,
and Subscription Receipts were converted as at October 31, 2012 is as
follows. 


 
----------------------------------------------------------------------------
Conversion of Securities into Common Shares (Unaudited)                     
As at October 31, 2012                                             Number of
                                                               Common Shares
Security                                                          (millions)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock Options                                                            5.1
First Preference Shares, Series C                                        3.9
First Preference Shares, Series E                                        6.2
Subscription Receipts                                                   18.5
----------------------------------------------------------------------------
Total                                                                   33.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Additional information, including the Fortis 2011 Annual Information
Form, Management Information Circular and Annual Report, is available
on SEDAR at www.sedar.com and on the Corporation's website at
www.fortisinc.com. 


 
FORTIS INC.                                                                 
                                                                            
Interim Consolidated Financial Statements                                   
For the three and nine months ended September 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)                     
                                                                            
                                              September 30,    December 31, 
                                                       2012            2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                  (Note 22) 
ASSETS                                                                      
                                       
                                     
Current assets                                                              
Cash and cash equivalents                     $         147   $          87 
Accounts receivable                                     410             638 
Prepaid expenses                                         33              19 
Inventories                                             157             134 
Regulatory assets (Note 3)                               98             219 
Deferred income taxes                                    24              24 
                                            --------------------------------
                                                        869           1,121 
                                                                            
Other assets                                            209             184 
Regulatory assets (Note 3)                            1,493           1,400 
Deferred income taxes                                     1               8 
Utility capital assets                                9,374           8,968 
Income producing properties                             604             594 
Intangible assets                                       322             325 
Goodwill (Note 12)                                    1,566           1,565 
                                            --------------------------------
                                                                            
                                              $      14,438   $      14,165 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
LIABILITIES AND SHAREHOLDERS' EQUITY                                        
                                                                            
Current liabilities                                                         
Short-term borrowings (Note 17)               $          97   $         159 
Accounts payable and other current                                          
 liabilities                                            855             990 
Regulatory liabilities (Note 3)                          75              43 
Current installments of long-term debt                   90             103 
Current installments of capital lease and                                   
 finance obligations                                      7               7 
Deferred income taxes                                     2               5 
                                            --------------------------------
                                                      1,126           1,307 
                                                                            
Other liabilities                                       577             573 
Regulatory liabilities (Note 3)                         588             555 
Deferred income taxes                                   733             673 
Long-term debt                                        5,847           5,685 
Capital lease and finance obligations                   434             429 
                                            --------------------------------
                                                      9,305           9,222 
                                            --------------------------------
                                                                            
Shareholders' equity                                                        
Common shares (a)(Note 4)                             3,092           3,036 
Preference shares                                       912             912 
Additional paid-in capital                               15              14 
Accumulated other comprehensive loss                    (97)            (95)
Retained earnings                                       923             868 
                                            --------------------------------
                                                      4,845           4,735 
Non-controlling interests (Note 5)                      288             208 
                                            --------------------------------
                                                      5,133           4,943 
                                            --------------------------------
                                                                            
                                              $      14,438   $      14,165 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(a)  no par value: unlimited authorized shares; 190.7 million and 188.8     
     million issued and outstanding as at                                   
     September 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 September 30                     
         (in millions of Canadian dollars, except per share amounts)        
                                                                            
                                          Quarter Ended    Nine Months Ended
                                         2012      2011      2012       2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Revenue                              $    714  $    699  $  2,655   $  2,704
                                   -----------------------------------------
                                                                            
Expenses                                                                    
  Energy supply costs                     235       246     1,092      1,207
  Operating                               203       200       621        619
  Depreciation and amortization           118       104       351        309
                                   -----------------------------------------
                                          556       550     2,064      2,135
                                   -----------------------------------------
                                                                            
Operating income                          158       149       591        569
                                                                            
Other income (expenses), net (Note                                          
 8)                                         1        22        (2)        34
Finance charges (Note 9)                   93        89       276        274
                                   -----------------------------------------
                                                                            
Earnings before income taxes               66        82       313        329
                                                                            
Income taxes (Note 10)                      7        12        44         59
                                   -----------------------------------------
                           
                                                 
Net earnings                         $     59  $     70  $    269   $    270
                                   -----------------------------------------
                                   -----------------------------------------
                                                                            
Net earnings attributable to:                                               
  Non-controlling interests          $      3  $      3  $      7   $      7
  Preference equity shareholders           11        11        34         34
  Common equity shareholders               45        56       228        229
                                   -----------------------------------------
                                     $     59  $     70  $    269   $    270
                                   -----------------------------------------
                                   -----------------------------------------
                                                                            
Earnings per common share (Note 11)                                         
  Basic                              $   0.24  $   0.30  $   1.20   $   1.28
  Diluted                            $   0.24  $   0.30  $   1.19   $   1.27
                                                                            
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
See accompanying Notes to Interim Consolidated Financial Statements         
                                                                            
                                                                            
                                                                            
                                 Fortis Inc.                                
         Consolidated Statements of Comprehensive Income (Unaudited)        
                     For the periods ended September 30                     
                      (in millions of Canadian dollars)                     
                                                                            
                                            Quarter Ended  Nine Months Ended
                                           2012      2011     2012      2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Net earnings                            $    59   $    70  $   269   $   270
                                      --------------------------------------
                                      --------------------------------------
                                                                            
Other comprehensive (loss) income                                           
Unrealized foreign currency                                                 
 translation (losses) gains, net of                                         
 hedging activities and tax                  (3)        8       (3)        5
Reclassification of unrealized foreign                                      
 currency translation losses, net of                                        
 hedging activities and tax, related                                        
 to Belize Electricity                        -         -        -        17
Reclassification to earnings of net                                         
 losses on discontinued cash flow                                           
 hedges, net of tax                           -         1        -         1
Unrealized employee future benefits                                         
 gains, net of tax                            -         -        1         -
                                      --------------------------------------
                                             (3)        9       (2)       23
                                      --------------------------------------
                                                                            
Comprehensive income                    $    56   $    79  $   267   $   293
                                      --------------------------------------
                                      --------------------------------------
                                                                            
Comprehensive income attributable to:                                       
  Non-controlling interests             $     3   $     3  $     7   $     7
  Preference equity shareholders             11        11       34        34
  Common equity shareholders                 42        65      226       252
                                      --------------------------------------
                                        $    56   $    79  $   267   $   293
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
See accompanying Notes to Interim Consolidated Financial Statements         
                                                                            
                                                                            
                                                                            
                                 Fortis Inc.                                
              Consolidated Statements of Cash Flows (Unaudited)             
                     For the periods ended September 30                     
                      (in millions of Canadian dollars)                     
                                                                            
                                          Quarter Ended   Nine Months Ended 
                                         2012      2011      2012      2011 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Operating activities                                                        
Net earnings                          $    59   $    70   $   269   $   270 
Adjustments to reconcile net                                                
 earnings to net cash provided by                                           
 operating activities:                                                      
  Depreciation - utility capital                                            
   assets and income producing                                              
   properties                             105        95       316       284 
  Amortization - intangible assets         12         9        33        27 
  Amortization - other                      1         -         2        (2)
  Deferred income taxes                     -         4         8         3 
  Accrued employee future benefits          3         4        (4)       13 
  Equity component of allowance for                                         
   funds used construction (Note 8)        (1)       (2)       (4)      (10)
  Other                                     1         -       (10)        4 
Change in long-term regulatory                                              
 assets and liabilities                   (16)      (27)      (25)       (9)
Change in non-cash operating working                                        
 capital (Note 14)                         57        (2)      219       104 
                                    ----------------------------------------
                                          221       151       804       684 
                                    ----------------------------------------
                             
                                               
Investing activities                                                        
Change in other assets and other                                            
 liabilities                               (2)        3         2         1 
Capital expenditures - utility                                              
 capital assets                          (264)     (259)     (737)     (745)
Capital expenditures - income                                               
 producing properties                      (9)      (11)      (24)      (20)
Capital expenditures - intangible                                           
 assets                                   (10)      (16)      (33)      (39)
Contributions in aid of construction       15        18        45        49 
Proceeds on sale of utility capital                                         
 assets and income producing                                                
 properties                                 -         -         -         6 
Business acquisitions, net of cash                                          
 acquired (Note 12)                        (7)        -       (14)        - 
                                    ----------------------------------------
                                         (277)     (265)     (761)     (748)
                                    ----------------------------------------
                                                                            
Financing activities                                                        
Change in short-term borrowings            17        86       (61)     (114)
Proceeds from long-term debt, net of                                        
 issue costs                                -         9         -        39 
Repayments of long-term debt and                                            
 capital lease and finance                                                  
 obligations                                -        (3)      (57)      (27)
Net (repayments) borrowings under                                           
 committed credit facilities               (9)     (178)      221      (105)
Advances from non-controlling                                               
 interests                                 14        20        83        77 
Subscription Receipts issue costs                                           
 (Note 4)                                  (1)        -       (13)        - 
Issue of common shares, net of costs                                        
 and dividends reinvested                   6        40        12       341 
Dividends                                                                   
  Common shares, net of dividends                                           
   reinvested                             (42)      (38)     (128)     (109)
  Preference shares                       (11)      (11)      (34)      (34)
  Subsidiary dividends paid to non-                                         
   controlling interests                   (2)       (2)       (6)       (6)
                                    ----------------------------------------
                                          (28)      (77)       17        62 
                                    ----------------------------------------
                                                                            
Effect of exchange rate changes on                                          
 cash and cash equivalents                  -         1         -         1 
                                    ----------------------------------------
                                                                            
Change in cash and cash equivalents       (84)     (190)       60        (1)
                                                                            
Cash and cash equivalents, beginning                                        
 of period                                231       296        87       107 
                                    ----------------------------------------
                                                                            
Cash and cash equivalents, end of                                           
 period                               $   147   $   106   $   147   $   106 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
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 September 30                     
                      (in millions of Canadian dollars)                     
                                                                            
                                          Accu-                             
                                        mulated                             
                                 Addi-    Other               Non-          
                        Prefe-  tional  Compre-           Control-          
                Common   rence Paid-in  hensive Retained      ling    Total 
                Shares  Shares Capital     Loss Earnings Interests   Equity 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
              (Note 4)                                                      
                                                                            
As at December                                                              
 31, 2011     $  3,036$    912$     14 $    (95)$    868 $     208 $  4,943 
                                                                            
Net earnings         -       -       -        -      262         7      269 
                                                                            
Other                                                                       
 comprehensive                                                              
 income              -       -       -       (2)       -         -       (2)
Common share                                                                
 issues             56       -      (1)       -        -         -       55 
Stock-based                                                                 
 compensation        -       -       2        -        -         -        2 
Advances from                                                               
 non-                                                                       
 controlling                                                                
 interests           -       -       -        -        -        83       83 
Foreign                                                                     
 currency                                                                   
 translation                                                                
 impacts             -       -       -        -        -        (4)      (4)
Subsidiary                                                                  
 dividends                                                                  
 paid to non-                                                               
 controlling                                                                
 interests           -       -       -        -        -        (6)      (6)
Dividends        
                                                           
 declared on                                                                
 common shares                                                              
 ($0.90 per                                                                 
 share)              -       -       -        -     (173)        -     (173)
Dividends                                                                   
 declared on                                                                
 preference                                                                 
 shares              -       -       -        -      (34)        -      (34)
              --------------------------------------------------------------
                                                                            
As at                                                                       
 September 30,                                                              
 2012         $  3,092$    912$     15 $    (97)$    923 $     288 $  5,133 
----------------------------------------------------------------------------
                                                                            
As at December                                                              
 31, 2010     $  2,575$    912$     12 $   (108)$    774 $     162 $  4,327 
                                                                            
Net earnings         -       -       -        -      263         7      270 
                                                                            
Other                                                                       
 comprehensive                                                              
 income              -       -       -       23        -         -       23 
Common share                                                                
 issues            395       -      (2)       -        -         -      393 
Stock-based                                                                 
 compensation        -       -       3        -        -         -        3 
Advances from                                                               
 non-                                                                       
 controlling                                                                
 interests           -       -       -        -        -        77       77 
Foreign                                                                     
 currency                                                                   
 translation                                                                
 impacts             -       -       -        -        -         3        3 
Subsidiary                                                                  
 dividends                                                                  
 paid to non-                                                               
 controlling                                                                
 interests           -       -       -        -        -        (6)      (6)
Expropriation                                                               
 of Belize                                                                  
 Electricity                                                                
 (Notes 16, 17                                                              
 and 19)             -       -       -        -        -       (38)     (38)
Dividends                                                                   
 declared on                                                                
 common shares                                                              
 ($0.87 per                                                                 
 share)              -       -       -        -     (159)        -     (159)
Dividends                                                                   
 declared on                                                                
 preference                                                                 
 shares              -       -       -        -      (34)        -      (34)
              --------------------------------------------------------------
                                                                            
As at                                                                       
 September 30,                                                              
 2011         $  2,970$    912$     13 $    (85)$    844 $     205 $  4,859 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
See accompanying Notes to Interim Consolidated Financial Statements         
                                                                            
                                                                            
                                                                            
                                 FORTIS INC.                                
             NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS             
   For the three and nine months ended September 30, 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;
    three small wholly owned utilities in the Turks and Caicos Islands,
    which include Turks and Caicos Utilities Limited ("TCU"), acquired in
    August 2012, FortisTCI Limited and Atlantic Equipment & Power (Turks and
    Caicos) Ltd. (collectively "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 ("GOB") expropriated the Corporation's investment
    in Belize El
ectricity. 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. 
NON-REGULATED - FORTIS PROPERTIES 
Fortis Properties owns and operates 23 hotels, collectively
representing more than 4,400 rooms, in eight Canadian provinces,
including the acquisition of the StationPark All Suite Hotel in
London, Ontario, which was acquired on October 1, 2012. Fortis
Properties also owns and operates 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 and the net expenses of non-regulated FortisBC Holdings Inc.
("FHI") corporate-related activities. Also included in the Corporate
and Other segment are the financial results of FHI's 30% ownership
interest in CustomerWorks Limited Partnership ("CWLP") and of FHI's
wholly owned subsidiary FortisBC Alternative Energy Services Inc.
("FAES"). 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. FAES provides alternative energy solutions. 
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 and the
Committee on Foreign Investment in the United States in July 2012. In
addition, the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976 expired in October 2012, satisfying another
condition necessary for consummation of the transaction. 
The transaction remains subject to approval by the New York State
Public Service Commission ("NYSPSC") and satisfaction of customary
closing conditions. The application for approval of the transaction
by the NYSPSC was 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 (Notes 8 and
18). 
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 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. Similarly,
FortisBC Electric recorded the cumulative impacts of its revenue
requirements decision, effective January 1, 2012, in the third
quarter of 2012 when the decision was received. 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 nine months ended September
30, 2012, except as described further with respect to capital asset
depreciation.  
An evaluation of subsequent events through to October 31, 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 September 30, 2012 (Note 21). 
All amounts are presented in Canadian dollars unless otherwise
stated. 
These interim consolidated financial statements include the accounts
of Fortis and its wholly owned subsidiaries and controlling ownership
interests. All significant intercompany balances and transactions
have been eliminated on consolidation.  
These interim consolidated financial statements have been prepared
following the same accounting policies and methods as those used 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 Im
pairment 
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 as of 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 nine months ended September 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 Application ("RRA")
and subsequently approved by the regulator in its April 2012
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 forecasted 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 nine months ended September 30, 2012, non-ARO removal costs of
approximately $5 million and $15 million, respectively, were accrued
as part of depreciation expense. For the three and nine months ended
September 30, 2011, non-ARO removal costs of approximately $4 million
and $12 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. As applied for in FortisBC Electric's 2012-2013
RRA and approved by the regulator, prospectively from January 1, 2012
the above-noted sharing of positive or negative variances is no
longer in effect. Beginning in 2012, variances between actual
electricity revenue and purchased power 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, do not impact net earnings in 2012.
Effective January 1, 2012, however, the flow through treatment for
finance charges, as was applied for in FortisBC Electric's 2012-2013
RRA, was denied by the regulator pursuant to its revenue requirements
decision. As a result, a retroactive adjustment was recorded in the
third quarter of 2012 to eliminate the flow through treatment.
Variances between actual finance charges from those forecasted in
determining customer electricity rates, therefore, have an impact on
net earnings in 2012.  
Effective January 1, 2012, as approved by the regulator, the FortisBC
Energy companies are deferring variances between actual depreciation
expense and that forecasted in determining customer gas rates. 
Effective January 1, 2012, as approved by the regulator,
FortisAlberta is no longer permitted to defer transmission volume
variances associated with its Alberta Electric System Operator
("AESO") charges deferral account. For the three and nine months
ended September 30, 2012, FortisAlberta recognized approximately $3.5
million and $6.5 million, respectively, of net transmission revenue
as a result of this change. 
Change in Estimates - Capital Asset Depreciation 
Changes in regulator-approved depreciation rates at FortisAlberta and
FortisBC Electric, in conjunction with approved depreciation studies
and revenue requirements decisions received in 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. FortisBC Electric's composite depreciation
rate for utility capital assets decreased to 3.1% for 2012 from 3.2%
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. 
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             
                                               September 30,   December 31, 
($ millions)                                            2012           2011 
----------------------------------------------------------------------------
Regulatory assets                                                           
Deferred income taxes                                    683            630 
Employee future benefits                                 406            428 
Deferred lease costs - FortisBC Electric                  81             70 
Rate stabilization accounts - electric                                      
 utilities                                                53             55 
Replacement energy deferral - Point Lepreau                                 
 (1)                                                      47             47 
Deferred energy management costs                          43             36 
Rate stabilization accounts - FortisBC Energy                               
 companies                                                31            105 
Deferred operating overhead costs                         30             22 
Customer Care Enhancement Project cost                                      
 deferral                                                 25             13 
Deferred net losses on disposal of utility                                  
 capital assets                                           25             23 
Income taxes recoverable on other post-                                     
 employment benefit ("OPEB") plans                        23             22 
Whistler pipeline contribution deferral                   16             16 
Pension cost variance deferral                            14             10 
Alternative energy projects cost deferral                 13              8 
Deferred development cos
ts for capital                    10             11 
Deferred costs - smart meters                              8              8 
AESO charges deferral                                      -             44 
Other regulatory assets                                   83             71 
----------------------------------------------------------------------------
Total regulatory assets                                1,591          1,619 
Less: current portion                                    (98)          (219)
----------------------------------------------------------------------------
Long-term regulatory assets                            1,493          1,400 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1)  New Brunswick Power Point Lepreau Nuclear Generating Station           
                                                                            
                                                                            
                                                                            
                                                          As at             
                                               September 30,   December 31, 
($ millions)                                            2012           2011 
----------------------------------------------------------------------------
Regulatory liabilities                                                      
Non-ARO removal cost provision                           374            354 
Rate stabilization accounts - FortisBC Energy                               
 companies                                               154            127 
Rate stabilization accounts - electric                                      
 utilities                                                36             33 
AESO charges deferral                                     33             12 
Deferred income taxes                                     15              9 
Deferred interest                                          8             10 
Performance-based rate-setting incentive                                    
 liabilities                                               8              7 
Income tax variance deferral                               6             12 
Southern Crossing Pipeline deferral                        5              8 
Unrecognized net gains on disposal of utility                               
 capital assets                                            -              6 
Other regulatory liabilities                              24             20 
----------------------------------------------------------------------------
Total regulatory liabilities                             663            598 
Less: current portion                                    (75)           (43)
----------------------------------------------------------------------------
Long-term regulatory liabilities                         588            555 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
4. COMMON SHARES 


 
Common shares issued during the period were as follows:                     
                                                                            
                                  Quarter Ended                 Year-to-Date
                             September 30, 2012           September 30, 2012
                       Number of                     Number of              
                          Shares         Amount         Shares        Amount
                  (in thousands)   ($ millions) (in thousands)  ($ millions)
----------------------------------------------------------------------------
Balance, beginning                                                          
 of period               189,967          3,071        188,828         3,036
  Dividend                                                                  
   Reinvestment                                                             
   Plan                      460             15          1,355            43
  Consumer Share                                                            
   Purchase Plan               8              -             32             1
  Employee Share                                                            
   Purchase Plan              63              2             63             2
  Stock Option                                                              
   Plans                     160              4            380            10
----------------------------------------------------------------------------
Balance, end of                                                             
 period                  190,658          3,092        190,658         3,092
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Effective May 4, 2012, the Corporation's Board of Directors approved
the 2012 Employee Share Purchase Plan ("2012 ESPP"). Under the 2012
ESPP, common shares may be issued from treasury, acquired in the open
market or a combination from treasury and the open market, as
determined by the Corporation. The first shares issued from treasury
under the 2012 ESPP occurred in September 2012.  
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., realizing gross proceeds of approximately $601
million. The gross proceeds from the sale of the Subscription
Receipts are being held by an escrow agent, pending satisfaction of
closing conditions, including receipt of regulatory approvals,
included in the agreement to acquire CH Energy Group ("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 agreement and plan of merger 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            
                                                September 30,   December 31,
($ millions)                                             2012           2011
----------------------------------------------------------------------------
Waneta Expansion Limited Partnership ("Waneta                               
 Partnership")                                            197            128
Caribbean Utilities                                        72             73
Mount Hayes Limited Partnership (Note 18)                  12              -
Preference shares of Newfoundland Power                     7              7
----------------------------------------------------------------------------
                                                          288            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 the granting of 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 nine months ended September 30, 2012, stock-based
compensation expense of approximately $2 million and $5 million,
respectively, was recognized ($2 million and $5 million for the three
and nine months ended September 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 September 30 
                                    Defined Benefit                         
                                      Pension Plans              OPEB Plans 
($ millions)                       2012        2011        2012        2011 
----------------------------------------------------------------------------
Components of net benefit                                                   
 cost:                                                                      
Service costs                         6           5           2           1 
Interest costs                       12          12           2           3 
Expected return on plan                                                     
 assets                             (12)        (12)          -           - 
Amortization of actuarial                                                   
 losses                               6           5           2           1 
Amortization of past service                                                
 costs/plan amendments                -           -           -          (1)
Regulatory adjustments               (2)         (2)          -           1 
----------------------------------------------------------------------------
Net benefit cost                     10           8           6           5 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
                                                  Year-to-Date September 30 
                                    Defined Benefit                         
                                      Pension Plans              OPEB Plans 
($ millions)                       2012        2011        2012        2011 
----------------------------------------------------------------------------
Components of net benefit                                                   
 cost:                                                                      
Service costs                        20          15           5           3 
Interest costs                       35          36           8           9 
Expected return on plan                                                     
 assets                             (37)        (36)          -           - 
Amortization of actuarial                                                   
 losses                              19          15           4           3 
Amortization of past service                                                
 costs/plan amendments                -           -          (2)         (3)
Amortization of transitional                                                
 obligation                           1           -           1           - 
Regulatory adjustments               (8)         (6)          1           3 
----------------------------------------------------------------------------
Net benefit cost                     30          24          17          15 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
For the three and nine months ended September 30, 2012, the
Corporation expensed $3 million and $10 million, respectively ($3
million and $11 million for the three and nine months ended September
30, 2011, respectively) related to defined contribution pension
plans. 
8. OTHER INCOME (EXPENSES), NET 


 
                                       Quarter Ended            Year-to-Date
                                        September 30            September 30
($ millions)                       2012         2011       2012         2011
----------------------------------------------------------------------------
Interest income                       2            2          4            4
Equity component of                                                         
 allowance for funds used                                                   
 during construction                  1            2          4           10
Foreign exchange (loss) gain         (2)           1         (2)           1
Acquisition-related expenses          -            -         (8)           -
Merger termination fee                -           17          -           17
Other income, net of                                      
                  
 expenses                             -            -          -            2
----------------------------------------------------------------------------
                                      1           22         (2)          34
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The foreign exchange loss for the three and nine months ended
September 30, 2012 included approximately $3 million and $2.5
million, respectively, related to the translation of the
Corporation's US dollar-denominated long-term other asset
representing the book value of the Corporation's expropriated
investment in Belize Electricity (Notes 17 and 19).  
The foreign exchange gain for the three and nine months ended
September 30, 2011 included a foreign exchange gain of $7 million
associated with the translation of the above-noted US
dollar-denominated long-term other asset, which was partially offset
by a $5.5 million ($4.5 million after tax) foreign exchange loss
associated with the translation of previously hedged US
dollar-denominated long-term debt.  
The acquisition-related expenses are associated with the pending
acquisition of CH Energy Group (Notes 1 and 18).  
The termination fee was paid to Fortis in July 2011 following the
termination of a Merger Agreement between Fortis and Central Vermont
Public Service Corporation. 
9. FINANCE CHARGES 


 
                                      Quarter Ended            Year-to-Date 
                                       September 30            September 30 
($ millions)                       2012        2011        2012        2011 
----------------------------------------------------------------------------
Interest:                                                                   
  Long-term debt and finance                                                
   and capital lease                                                        
   obligations                       95          91         282         275 
  Short-term borrowings and                                                 
   other finance charges              3           1           6          10 
Debt component of allowance                                                 
 for funds used during                                                      
 construction                        (5)         (3)        (12)        (11)
----------------------------------------------------------------------------
                                     93          89         276         274 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 
                                           September 30        September 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              19        25        91       100 
Difference between Canadian                                                 
 statutory income tax rate and rates                                        
 applicable to foreign subsidiaries        (3)       (4)      (10)       (9)
Difference in Canadian provincial                                           
 statutory income tax rates                                                 
 applicable to subsidiaries in                                              
 different Canadian jurisdictions          (1)       (1)       (9)       (9)
Items capitalized for accounting                                            
 purposes but expensed for income                                           
 tax purposes                             (11)      (11)      (39)      (39)
Difference between capital cost                                             
 allowance and amounts claimed for                                          
 accounting purposes                        3         5         7        11 
Non-deductible expenses                     2         2         5         3 
Part VI.1 tax - difference between                                          
 enacted and substantively enacted                                          
 tax rates and the effect of                                                
 statute-barred reversals                  (1)        -         2         2 
Difference between employee future                                          
 benefits paid and amounts expensed                                         
 for accounting purposes                    -        (1)        1        (1)
Other                                      (1)       (3)       (4)        1 
----------------------------------------------------------------------------
Income taxes                                7        12        44        59 
----------------------------------------------------------------------------
Effective income tax rate                10.6%     14.6%     14.1%     17.9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
As at September 30, 2012, the Corporation had approximately $100
million (December 31, 2011 - $86 million) in non-capital and capital
loss carryforwards, of which $8 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 September 30
                                          2012                        2011
                  --------------------------------------------------------
                   Earnings                      Earnings                 
                  to Common  Weighted           to Common  Weighted       
                     Share-   Average              Share-   Average       
                    holders    Shares             holders    Shares       
                         ($       (in                  ($       (in       
                  millions) millions)      EPS  millions) millions)    EPS
--------------------------------------------------------------------------
Basic EPS                45     190.2   $ 0.24         56     186.5 $ 0.30
Effect of                                                                 
 potential                                                                
 dilutive                                                                 
 securities:                                                              
  Stock Options           -       0.9                   -       1.0       
  Preference                                                              
   Shares                 4      10.3                   4      10.1       
  Convertible                                                             
   Debentures             -         -                   1       1.4       
--------------------------------------------------------------------------
                         49     201.4                  61     199.0       
Deduct anti-                                                              
 dilutive impacts:                                                        
  Preference                                                              
   Shares                (4)    (10.3)                 (4)    (10.1)      
  Convertible                                                             
   Debentures             -         -                  (1)     (1.4)      
--------------------------------------------------------------------------
Diluted EPS              45     191.1   $ 0.24         56     187.5 $ 0.30
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                          
                                                 Year-to-Date September 30
                                          2012                        2011
                  --------------------------------------------------------
                   Earnings                      Earnings                 
                  to Common  Weighted           to Common  Weighted       
                     Share-   Average              Share-   Average       
                    holders    Shares             holders    Shares       
                         ($       (in                  ($       (in       
                  millions) millions)      EPS  millions) millions)    EPS
--------------------------------------------------------------------------
Basic EPS               228     189.6   $ 1.20        229     179.5 $ 1.28
Effect of                                                                 
 potential                                                                
 dilutive                                                                 
 securities:                                                              
  Stock Options           -       0.9                   -       1.0       
  Preference                                                              
   Shares                12      10.3                  12      10.1       
  Convertible                                                             
   Debentures             -         -                   2       1.4       
--------------------------------------------------------------------------
                        240     200.8                 243     192.0       
Deduct anti-                                                              
 dilutive impacts:                                                        
  Preference                                                              
   Shares                (5)     (3.9)                 (5)     (3.9)      
--------------------------------------------------------------------------
Diluted EPS             235     196.9   $ 1.19        238     188.1 $ 1.27
--------------------------------------------------------------------------
--------------------------------------------------------------------------

 
12. BUSINESS ACQUISITIONS 
In April 2012 FortisOntario exercised its option, under the terms of
a 10-year operating lease agreement with the City of Port Colborne
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 of Port Colborne, and now through ownership
of the previously leased assets, FortisOntario operates and maintains
the City of Port Colborne'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 constitute 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.  
In August 2012 Fortis Turks and Caicos acquired TCU for an aggregate
purchase price of approximately $13 million (US$13 million),
inclusive of debt assumed of $5 million (US$5 million). TCU is a
regulated electric utility operating pursuant to a 50-year licence
expiring in 2036. The utility serves more than 2,000 residential and
commercial customers between Grand Turk and Salt Cay with a
diesel-fired generating capacity of 9 MW. Fortis Turks and Caicos 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 net assets acquired, because all
of the economic benefits and obligations associated with them beyond
regulated rates of return accrue to the customers. Accordingly,
approximately $9 million of the purchase price was allocated to
utility capital assets, $3 million to current net assets, $5 million
to long-term debt and $1 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                      New-           Total         
September 30,   Companies                    found-  Other Electric Electric
 2012                   -    Fortis FortisBC   land  Cana-    Cana-   Carib-
($ millions)     Canadian   Alberta Electric  Power   dian     dian     bean
----------------------------------------------------------------------------
Revenue               192       117       71    100     91      379       72
Energy supply                                                               
 costs                 61         -       16     54     59      129       45
Operating                                                                   
 expenses              64        40       20     17     11       88        7
Depreciation and                                                            
 amortization          40        34       12     11      7       64        8
----------------------------------------------------------------------------
Operating income       27        43       23     18     14       98       12
Other income                                                                
 (expenses), net        1         -        1      1      -        2        1
Finance charges        36        1
7        9      9      5       40        3
Income tax                                                                  
 (recovery)                                                                 
 expense               (2)        -        2      1      3        6        -
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings              (6)       26       13      9      6       54       10
Non-controlling                                                             
 interests              -         -        -      -      -        -        3
Preference share                                                            
 dividends              -         -        -      -      -        -        -
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings                                                                   
 attributable to                                                            
 common equity                                                              
 shareholders          (6)       26       13      9      6       54        7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill              913       227      221      -     67      515      138
Identifiable                                                                
 assets             4,503     2,617    1,686  1,244    705    6,252      735
----------------------------------------------------------------------------
Total assets        5,416     2,844    1,907  1,244    772    6,767      873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                   66       104       19     22     13      158       11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Quarter Ended                                                               
 September 30,                                                              
 2011($                                                                     
 millions)                                                                  
----------------------------------------------------------------------------
Revenue               197       103       67    101     87      358       74
Energy supply                                                               
 costs                 76         -       15     52     56      123       47
Operating                                                                   
 expenses              65        35       19     17     11       82        9
Depreciation and                                                            
 amortization          29        34       11     11      6       62        7
----------------------------------------------------------------------------
Operating income       27        34       22     21     14       91       11
Other income                                                                
 (expenses), net        2         -        -      -      -        -        -
Finance charges        36        15       10      9      5       39        2
Income tax                                                                  
 (recovery)                                                                 
 expense               (3)        -        2      4      3        9        -
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings              (4)       19       10      8      6       43        9
Non-controlling                                                             
 interests              -         -        -      -      -        -        3
Preference share                                                            
 dividends              -         -        -      -      -        -        -
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings                                                                   
 attributable to                                                            
 common equity                                                              
 shareholders          (4)       19       10      8      6       43        6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill              913       227      221      -     63      511      144
Identifiable                                                                
 assets             4,364     2,345    1,626  1,232    670    5,873      742
----------------------------------------------------------------------------
Total assets        5,277     2,572    1,847  1,232    733    6,384      886
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                   64        82       25     24     14      145       17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                     NON-REGULATED                          
                ----------------------------------                          
                                                                            
                                                                            
Quarter Ended                                            Inter-             
September 30,        Fortis     Fortis                  segment             
 2012                 Gene-    Proper-   Corporate       elimi-       Conso-
($ millions)         ration       ties   and Other      nations      lidated
----------------------------------------------------------------------------
Revenue                   8         65           5           (7)         714
Energy supply                                                               
 costs                    -          -           -            -          235
Operating                                                                   
 expenses                 2         42           2           (2)         203
Depreciation and                                                            
 amortization             1          5           -            -          118
----------------------------------------------------------------------------
Operating income          5         18           3           (5)         158
Other income                                                                
 (expenses), net          -          -          (3)           -            1
Finance charges           -          6          13           (5)          93
Income tax                                                                  
 (recovery)                                                                 
 expense                  -          4          (1)           -            7
----------------------------------
------------------------------------------
Net (loss)                                                                  
 earnings                 5          8         (12)           -           59
Non-controlling                                                             
 interests                -          -           -            -            3
Preference share                                                            
 dividends                -          -          11            -           11
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings                                                                   
 attributable to                                                            
 common equity                                                              
 shareholders             5          8         (23)           -           45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill                  -          -           -            -        1,566
Identifiable                                                                
 assets                 686        623         498         (425)      12,872
----------------------------------------------------------------------------
Total assets            686        623         498         (425)      14,438
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                     39          9           -            -          283
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Quarter Ended                                                               
 September 30,                                                              
 2011($                                                                     
 millions)                                                                  
----------------------------------------------------------------------------
Revenue                  11         63           4           (8)         699
Energy supply                                                               
 costs                    -          -           -            -          246
Operating                                                                   
 expenses                 2         40           4           (2)         200
Depreciation and                                                            
 amortization             1          5           -            -          104
----------------------------------------------------------------------------
Operating income          8         18           -           (6)         149
Other income                                                                
 (expenses), net          -          -          20            -           22
Finance charges           -          6          12           (6)          89
Income tax                                                                  
 (recovery)                                                                 
 expense                  -          3           3            -           12
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings                 8          9           5            -           70
Non-controlling                                                             
 interests                -          -           -            -            3
Preference share                                                            
 dividends                -          -          11            -           11
----------------------------------------------------------------------------
Net (loss)                                                                  
 earnings                                                                   
 attributable to                                                            
 common equity                                                              
 shareholders             8          9          (6)           -           56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill                  -          -           -            -        1,568
Identifiable                                                                
 assets                 539        589         507         (434)      12,180
----------------------------------------------------------------------------
Total assets            539        589         507         (434)      13,748
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                     49         11           -            -          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                     New-           Total         
September 30,    Companies                   found-  Other Electric Electric
 2012                    -   Fortis FortisBC   land  Cana-    Cana-   Carib-
($ millions)      Canadian  Alberta Electric  Power   dian     dian     bean
----------------------------------------------------------------------------
Revenue              1,004      335      225    422    264    1,246      202
Energy supply                                                               
 costs                 472        -       54    274    168      496      124
Operating                                                                   
 expenses              197      116       62     54     35      267       24
Depreciation and                                                            
 amortization          120       99       36     33     20      188       24
----------------------------------------------------------------------------
Operating income       215      120       73     61     41      295       30
Other income                                                                
 (expenses), net         2        2 
       1      2      -        5        2
Finance charges        107       49       29     27     16      121       10
Income tax                                                                  
 expense                                                                    
 (recovery)             20        -        7      8      7       22        -
----------------------------------------------------------------------------
Net earnings                                                                
 (loss)                 90       73       38     28     18      157       22
Non-controlling                                                             
 interests               1        -        -      -      -        -        6
Preference share                                                            
 dividends               -        -        -      -      -        -        -
----------------------------------------------------------------------------
Net earnings                                                                
 (loss)                                                                     
 attributable to                                                            
 common equity                                                              
 shareholders           89       73       38     28     18      157       16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill               913      227      221      -     67      515      138
Identifiable                                                                
 assets              4,503    2,617    1,686  1,244    705    6,252      735
----------------------------------------------------------------------------
Total assets         5,416    2,844    1,907  1,244    772    6,767      873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                   144      304       52     58     35      449       33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Year-to-Date                                                                
 September 30,                                                              
 2011($                                                                     
 millions)                                                                  
----------------------------------------------------------------------------
Revenue              1,090      306      215    417    256    1,194      234
Energy supply                                                               
 costs                 590        -       49    266    163      478      146
Operating                                                                   
 expenses              209      106       58     54     34      252       31
Depreciation and                                                            
 amortization           83      100       34     32     18      184       24
----------------------------------------------------------------------------
Operating income       208      100       74     65     41      280       33
Other income                                                                
 (expenses), net         8        3        1      -      -        4        2
Finance charges        106       44       29     27     16      116       11
Income tax                                                                  
 expense                                                                    
 (recovery)             24        1        8     14      7       30        1
----------------------------------------------------------------------------
Net earnings                                                                
 (loss)                 86       58       38     24     18      138       23
Non-controlling                                                             
 interests               -        -        -      -      -        -        7
Preference share                                                            
 dividends               -        -        -      -      -        -        -
----------------------------------------------------------------------------
Net earnings                                                                
 (loss)                                                                     
 attributable to                                                            
 common equity                                                              
 shareholders           86       58       38     24     18      138       16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
Goodwill               913      227      221      -     63      511      144
Identifiable                                                                
 assets              4,364    2,345    1,626  1,232    670    5,873      742
----------------------------------------------------------------------------
Total assets         5,277    2,572    1,847  1,232    733    6,384      886
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gross capital                                                               
 expenditures                                                               
 (1)                   177      253       78     55     33      419       57
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                                                          
                                                                          
                                                                          
                                    NON-REGULATED                         
                ----------------------------------                        
                                                                          
                                                                          
Year-to-Date                                           Inter-             
September 30,        Fortis     Fortis                segment             
 2012                 Gene-    Proper-  Corporate      elimi-      Conso- 
($ millions)         ration       ties  and Ot
her     nations     lidated 
--------------------------------------------------------------------------
Revenue                  26        181         18         (22)      2,655 
Energy supply                                                             
 costs                    1          -          -          (1)      1,092 
Operating                                                                 
 expenses                 6        124          8          (5)        621 
Depreciation and                                                          
 amortization             3         15          1           -         351 
--------------------------------------------------------------------------
Operating income         16         42          9         (16)        591 
Other income                                                              
 (expenses), net          1          -        (11)         (1)         (2)
Finance charges           1         18         36         (17)        276 
Income tax                                                                
 expense                                                                  
 (recovery)               1          7         (6)          -          44 
--------------------------------------------------------------------------
Net earnings                                                              
 (loss)                  15         17        (32)          -         269 
Non-controlling                                                           
 interests                -          -          -           -           7 
Preference share                                                          
 dividends                -          -         34           -          34 
--------------------------------------------------------------------------
Net earnings                                                              
 (loss)                                                                   
 attributable to                                                          
 common equity                                                            
 shareholders            15         17        (66)          -         228 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                          
Goodwill                  -          -          -           -       1,566 
Identifiable                                                              
 assets                 686        623        498        (425)     12,872 
--------------------------------------------------------------------------
Total assets            686        623        498        (425)     14,438 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital                                                             
 expenditures                                                             
 (1)                    144         24          -           -         794 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                          
Year-to-Date                                                              
 September 30,                                                            
 2011($                                                                   
 millions)                                                                
--------------------------------------------------------------------------
Revenue                  25        173         17         (29)      2,704 
Energy supply                                                             
 costs                    1          -          -          (8)      1,207 
Operating                                                                 
 expenses                 6        117          9          (5)        619 
Depreciation and                                                          
 amortization             3         14          1           -         309 
--------------------------------------------------------------------------
Operating income         15         42          7         (16)        569 
Other income                                                              
 (expenses), net          1          -         20          (1)         34 
Finance charges           2         18         38         (17)        274 
Income tax                                                                
 expense                                                                  
 (recovery)               1          6         (3)          -          59 
--------------------------------------------------------------------------
Net earnings                                                              
 (loss)                  13         18         (8)          -         270 
Non-controlling                                                           
 interests                -          -          -           -           7 
Preference share                                                          
 dividends                -          -         34           -          34 
--------------------------------------------------------------------------
Net earnings                                                              
 (loss)                                                                   
 attributable to                                                          
 common equity                                                            
 shareholders            13         18        (42)          -         229 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                          
Goodwill                  -          -          -           -       1,568 
Identifiable                                                              
 assets                 539        589        507        (434)     12,180 
--------------------------------------------------------------------------
Total assets            539        589        507        (434)     13,748 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Gross capital                                                             
 expenditures                                                             
 (1)                    131         20          -           -         804 
--------------------------------------------------------------------------
--------------------------------------------------------------------------
                                                                            
(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 nine months ended September 30, 2012
and 2011 were as follows: 


 
Significant Inter-Segment                                                   
 Transactions                              Quarter Ended        Year-to-Date
                                            September 30        September 30
($ millions)                              2012      2011      2012      2011
----------------------------------------------------------------------------
Sales from Fortis Generation to                                             
  Regulated Electric Utilities -                                            
   Caribbean                                 -         -         -         7
Sales from Fortis Generation to                                             
  Other Canadian Electric Utilities          -         -         -         1
Sales from Newfoundland Power to                                            
 Fortis Properties                           1         1         4         3
Inter-segment finance charges on                                            
 lending from:                                                 
             
  Fortis Generation to Other                                                
   Canadian Electric Utilities               -         -         1         1
  Corporate to Regulated Electric                                           
   Utilities - Canadian                      -         1         -         2
  Corporate to Regulated Electric                                           
   Utilities - Caribbean                     1         1         3         3
  Corporate to Fortis Generation             -         1         1         2
  Corporate to Fortis Properties             4         3        12         9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
The significant inter-segment asset balances were as follows:               
                                                          As at September 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                                        84        78
  Corporate to Fortis Generation                                12        32
  Corporate to Fortis Properties                               284       226
Other inter-segment assets                                      25        28
----------------------------------------------------------------------------
Total inter-segment eliminations                               425       434
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH
FLOWS 


 
                                          Quarter Ended        Year-to-Date 
                                           September 30        September 30 
($ millions)                             2012      2011      2012      2011 
----------------------------------------------------------------------------
Cash paid for:                                                              
Interest                                   84        79       269       260 
Income taxes                               12        16        63        61 
                                                                            
Change in non-cash operating working                                        
 capital:                                                                   
Accounts receivable                        96       115       224       184 
Prepaid expenses                           (8)       (8)      (14)      (15)
Inventories                               (48)      (84)      (21)      (28)
Regulatory assets - current portion         2       (15)       50       (21)
Accounts payable and other current                                          
 liabilities                               28         4       (39)      (34)
Regulatory liabilities - current                                            
 portion                                  (13)      (14)       19        18 
----------------------------------------------------------------------------
                                           57        (2)      219       104 
                                    ----------------------------------------
                                    ----------------------------------------
                                                                            
Non-cash investing and financing                                            
 activities:                                                                
Common share dividends reinvested          15        16        43        47 
Exercise of stock options into                                              
 common shares                              -         -         1         2 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 September
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 September 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                                          
 imperial gallons)                                 4           3           -
Gas swaps and options (petajoules)                 4          26           6
Gas purchase contract premiums                                              
 (petajoules)                                     94          17           1
----------------------------------------------------------------------------

 
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 Corporation's outstanding derivative balances were as follows: 


 
                                                           As at            
                                                September 30,   December 31,
($ millions)                                             2012           2011
----------------------------------------------------------------------------
Gross derivatives balance (1)                              59            136
Netting (2)                                                 -              -
Cash collateral                                             -              -
----------------------------------------------------------------------------
Total derivative balances (3)                              59            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 $34 million on commodity risk-related derivative  
     instruments as at September 30, 2012 were recognized in current        
     regulatory assets and $25 million were recognized as an offset to      
     current regulatory liabilities (December 31, 2011 - $136 million       
     recognized i
n current regulatory assets), which would otherwise be     
     recognized on the consolidated statement of comprehensive income and in
     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 record all derivative
instruments at fair value except for those which qualify for the
normal purchase and normal sale exception. 
The three levels of the fair value hierarchy are defined as follows: 


 
Level 1:  Fair value determined using unadjusted quoted prices in active    
          markets                                                           
Level 2:  Fair value determined using pricing inputs that are observable    
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)                September 30, 2012       December 31, 2011 
                               Carrying   Estimated    Carrying   Estimated 
($ millions)                      Value  Fair Value       Value  Fair Value 
----------------------------------------------------------------------------
Other asset - Belize                                                        
 Electricity (1)                    103       - (2)         106       - (2) 
Long-term debt, including                                                   
 current portion (3)             (5,937)     (7,476)     (5,788)     (7,172)
Waneta Partnership                                                          
 promissory note (4)                (46)        (52)        (45)        (49)
Foreign exchange forward                                                    
 contract (5)                         -           -           -           - 
Fuel option contracts (5)             -           -          (1)         (1)
Natural gas derivatives: (5)                                                
  Swaps and options                 (60)        (60)       (135)       (135)
  Gas purchase contract                                                     
   premiums                           1           1           -           - 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(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 appropriate fair value 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 (Notes 17 and 19).                            
                                                                            
(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 September 30, 2012 and December 31,
     2011. The fair value of the fuel option contracts as at September 30,  
     2012 were less than $1 million. The foreign exchange forward contract  
     held by FEI expired in April 2012. The fair value of the contract was  
    less than $1 million as at December 31, 2011.                          

 
The fair value of long-term debt is calculated using quoted market
prices when available. When quoted market prices are not available,
the fair value is determined by discounting the future cash flows of
the specific debt instrument at an estimated yield to maturity
equivalent to benchmark government bonds or treasury bills, with
similar terms to maturity, plus a credit risk premium equal to that
of issuers of similar credit quality. Since the Corporation does not
intend to settle the long-term debt 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. In
October 2012 Caribbean Utilities executed additional fuel option
contracts covering the period from November 1, 2012 to October 31,
2013. With the execution of these new contracts, approximately 70% of
the Company's annual diesel fuel requirements are under fuel hedging
arrangements.  
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 September 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 September 30, 2012, the utility's gross credit risk
exposure was approximately $57 million, representing the projected
value of retailer billings over a 37-day period. The Company has
reduced its exposure to less than $1 million by obtaining from the
retailers an acceptable form of prudential, which includes 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 reasonable credit-quality institutions in
accordance with established credit-approval practices. The FortisBC
Energy companies do not expect any counterparties to fail to meet
their obligations. The counterparties with which the FortisBC Energy
companies have significant derivative 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 counterparties accounting for greater than 10% net credit
exposure, as it relates to its natural gas swaps and options. 


 
                                                           As at            
                                                September 30,   December 31,
($ millions, except for number of customers)             2012           2011
----------------------------------------------------------------------------
Gross credit exposure before credit collateral                              
 (1)                                                       60            136
Credit collateral                                           -              -
----------------------------------------------------------------------------
Net credit exposure (2)                                    60            136
----------------------------------------------------------------------------
                                                                            
Number of counterparties greater than 10%                  4              4
Net exposure to counterparties greater than                                
 10%                                                       53            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 fair value 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. As at September 30, 2012, the Corporation had a long-term other
asset of $103 million (December 31, 2011 - $106 million; September
30, 2011 - $103 million), including foreign exchange impacts,
recognized on the consolidated balance sheet related to its
expropriated investment in Belize Electricity (Notes 16 and 19). 
Additionally, as at September 30, 2012, Belize Electricity owed
Belize Electric Company Limited ("BECOL") approximately US$10 million
for energy purchases of which US$6 million was overdue. In accordance
with long-standing agreements, the GOB guarantees the payment of
Belize Electricity's obligations to BECOL. 
Liquidity Risk 
The Corporation's consolidated financial position could be adversely
affected if it, or one of its subsidiaries, fails to arrange
sufficient and cost-effective financing to fund, among other things,
capital expenditures and the repayment of maturing debt. The ability
to arrange sufficient and cost-effective financing is subject to
numerous factors, including the consolidated results of operations
and financial position of the Corporation and its subsidiaries,
conditions in capital and bank credit markets, ratings assigned by
rating agencies and general economic conditions.  
To help mitigate liquidity risk, the Corporation and its larger
regulated utilities have secured committed credit facilities to
support short-term financing of capital expenditures and seasonal
working capital requirements.  
The Corporation's committed 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 September 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 September 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 
                                                        September  December 
                      Regulated      Fortis  Corporate        30,       31, 
($ millions)          Utilities  Properties  and Other       2012      2011 
----------------------------------------------------------------------------
Total credit                                                                
 facilities               1,401          13      1,045      2,459     2,248 
Credit facilities                                                           
 utilized:                                                                  
  Short-term                                                                
   borrowings (1)           (97)          -          -        (97)     (159)
  Long-term debt (2)        (63)          -       (236)      (299)      (74)
Letters of credit                                                           
 outstanding                (67)          -         (1)       (68)      (66)
----------------------------------------------------------------------------
Credit facilities                                                           
 unused                   1,174          13        808      1,995     1,949 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                                                            
(1)  The weighted average interest rate on short-term borrowings was        
     approximately 2.2% as at September 30, 2012 (December 31, 2011 - 1.9%).
                                                                            
(2)  As at September 30, 2012, credit facility borrowings classified as long
     term included $20 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 2.2% as at   
     September 30, 2012 (December 31, 2011 - 2.2%).                         

 
As at September 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 from August 2015 to August
2017. 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 unsecured 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, extending the
maturity date from August 2013 to August 2014. The amended credit
facility 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 from September 2015 to August 2016.
The amended credit facility agreement reflects a decrease in pricing
but, 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 September 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. Due to the Corporation's financing
plans for the pending acquisition of CH Energy Group and the expected
completion of the Waneta Expansion hydroelectric generating facility
on time and on budget, S&P and DBRS also 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.  
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 BECOL is the US dollar. Belize
Electricity's financial results were denominated in Belizean dollars,
which are pegged to the US dollar. 
As at September 30, 2012, the Corporation's corporately issued US$557
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 September 30, 2012, the Corporation had
approximately US$19 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
expropriated investment in Belize Electricity does not qualify for
hedge accounting as Belize Electricity is no longer a foreign
subsidiary of Fortis. As a result, 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 long-term other 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. The Corporation has recognized in earnings
foreign exchange losses of approximately $3 million and $2.5 million
during the three and nine months ended September 30, 2012,
respectively. During the third quarter of 2011, a foreign exchange
gain of $7 million associated with the translation of the above-noted
US dollar-denominated long-term other asset was partially offset by a
$5.5 million ($4.5 million after tax) foreign exchange loss
associated with the translation of previously hedged US
dollar-denominated long-term debt, resulting in a net foreign
exchange gain of approximately $2.5 million after tax.  
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 most of its subsidiaries are exposed to interest
rate risk associated with short-term borrowings and floating-rate
debt. The Corporation and the 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 and
Caribbean Utilities is exposed to commodity price risk associated
with changes in the market price for fuel (Note 16). The risks have
been reduced by entering into natural gas derivatives and fuel option
contracts that effectively fix the price of natural gas purchases and
fuel purchases, respectively. The natural gas derivatives and fuel
option contracts are recorded on the consolidated balance sheet at
fair value and any change in the fair value is deferred as a
regulatory asset or liability, 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. As directed by
the regulator in 2011, the FortisBC Energy companies have suspended
their commodity hedging activities with the exception of certain
limited swaps as permitted by the regulator. The existing hedging
contracts will continue in effect through to their maturity and the
FortisBC Energy companies' ability to fully recover the commodity
cost of gas in customer rates remains unchanged. Any differences
between the cost of natural gas purchased and the price of natural
gas included in customer rates are recorded as regulatory deferrals
and are recovered from, or refunded to, customers in future rates,
subject to regulatory approval.  
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 as follows. 


 
a.  Pending Acquisitions

 
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 the Federal Energy Regulatory Commission and
the Committee on Foreign Investment in the United States in July
2012. In addition, the waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976 expired in October 2012,
satisfying another condition necessary for consummation of the
transaction. The transaction remains subject to approval by the
NYSPSC and satisfaction of customary closing conditions. The
application for approval of the transaction by the NYSPSC was jointly
filed by Fortis and CH Energy Group in April 2012 (Note 1). 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.  
The agreement and plan of merger may be terminated by the Corporation
or CH Energy Group at any time prior to closing in certain
circumstances, including if the acquisition has not closed by
February 20, 2013, provided, however, that if the only unsatisfied
conditions to closing are the obtaining of the regulatory approvals
as defined in the agreement and plan of merger, then such date shall
be extended to August 20, 2013. 
FortisBC Electric has offered to purchase the City of Kelowna's
electrical utility assets, which currently serve approximately 15,000
customers, for approximately $55 million. FortisBC Electric provides
the City of Kelowna with electricity under a wholesale tariff and has
operated and maintained the City of Kelowna's electrical utility
assets since 2000. Closing of the transaction is subject to certain
conditions and receipt of certain approvals, including regulatory
approval. The parties are working towards closing the transaction by
the end of the first quarter of 2013. 


 
b.  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, realizing gross proceeds of approximately $601 million. Each
Subscription Receipt will entitle the holder thereof 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. If the Release
Conditions are not satisfied by June 30, 2013, or if the agreement
and plan of merger relating to the acquisition 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 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. 
In September 2012 Caribbean Utilities entered into primary and
secondary fuel supply contracts with two different suppliers and is
committed to purchasing approximately 60% and 40% of the Company's
diesel fuel requirements under each of the contracts, respectively,
for the operation of Caribbean Utilities' diesel-powered generating
plant. The approximate combined quantities under the contracts,
expressed in millions of imperial gallons, on an annual basis by
fiscal year are: 2012 - 10.8, 2013 - 32.4 and 2014 - 18.9. The
contracts expire in July 2014 with the option to renew for two
additional 18-month terms. The renewal options can be exercised only
within six months of the expiry dates of the existing contracts.  
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.
Consequent to the deprivation of control over 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, including foreign exchange impacts, of the
expropriated 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.
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 book value of the
long-term other asset is below fair value as at the date of
expropriation as determined under the Corporation's valuation. 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 both the fair value determined under the Corporation's
valuation and the book value of the long-term other asset.  
In July 2012 the Belize Supreme Court dismissed the Corporation's
claim of October 2011. Also in July 2012, Fortis filed its appeal of
the above-noted trial judgment in the Belize Court of Appeal. The
appeal was heard in October 2012 and a decision on the appeal has
been suspended pending the outcome of another related appeal in the
Caribbean Court of Justice ("CCJ"). A possible outcome of the appeal
could be the return to Fortis of the majority ownership interest in
Belize Electricity. Alternatively, in the event that the Belize Court
of Appeal decision confirms the trial judgment, Fortis could pursue
an appeal of the case to the CCJ, the highest court of appeal
available for judical matters in Belize. 
Fortis believes it has a strong, well-positioned case before the
Belize Courts and will continue to vigorously litigate the legality
of the expropriation. There exists, however, a reasonable possibility
that the outcome of the above-noted litigation may be unfavourable to
the Corporation and the amount of compensation to be paid to Fortis
could be lower than the book value of its expropriated investment in
Belize Electricity, which was $103 million, including foreign
exchange impacts, as at September 30, 2012 (December 31, 2011 - $106
million; September 30, 2011 - $103 million) and recorded in long-term
other assets on the consolidated balance sheet. Based on presently
available information, the outcome of the above is not determinable
at this time. As such, the long-term other asset is not deemed
impaired. Fortis will continue to assess for impairment each
reporting period based on the outcomes of court proceedings and/or
compensation settlement negotiations, if any. As well as continuing
its legal actions, Fortis is also pursuing alternative options for
obtaining fair compensation.  
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
is appealing these 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 filed a statement of defence. During the second
quarter of 2010, FHI was added as a third party in all of the related
actions. FHI was advised that all matters have now been settled and
the action has been dismissed by consent. 
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. SUBSEQUENT EVENT 
In October 2012 FortisAlberta issued 40-year $125 million 3.98%
unsecured debentures, the proceeds from which are being used to repay
borrowings under the Company's credit facility, fund future capital
expenditures, and for general corporate purposes.  
22. 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.
Contacts:
Barry V. Perry
Vice President Finance and Chief Financial Officer
Fortis Inc.
709.737.2822
 
 
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